Use of a borate-acid buffer in oil and gas operations

ABSTRACT

Provided herein are compositions comprising borate-acid buffers, as well as methods of using these compositions in oil and gas operations, including enhanced oil recovery (EOR) operations, fracturing operations, stimulation operations, etc.

CROSS REFERENCES TO RELATED APPLICATIONS

This application is a divisional of U.S. application Ser. No.16/528,183, filed Jul. 31, 2019, which claims benefit of U.S.Provisional Application No. 62/712,944, filed Jul. 31, 2018, each ofwhich is hereby incorporated herein by reference in its entirety.

BACKGROUND

Reservoir systems, such as petroleum reservoirs, typically containfluids such as water and hydrocarbons (such as oil and gas). To remove(“produce”) the hydrocarbons from the reservoir, different mechanismscan be utilized including primary, secondary or tertiary processes,fracturing, stimulation, etc. For example, in a primary recoveryprocess, hydrocarbons are displaced from a reservoir through the highnatural differential pressure between the reservoir and the bottom-holepressure within a wellbore. In order to increase the production life ofthe reservoir, secondary or tertiary recovery processes can be used(“enhanced oil recovery” or EOR). Secondary recovery processes includewater or gas well injection, while tertiary methods are based oninjecting additional chemical compounds into the well, such assurfactants/solvents and polymers, for additional recovery. Thesurfactants/solvents free oil trapped in the pores of the reservoirrock, facilitate its production.

However, there remains a need for improved compositions, preparations,and methods for the production of hydrocarbons, particularly in the caseof recovery processes that employ hard water.

SUMMARY

Provided herein are compositions comprising borate-acid buffers, as wellas methods of using these compositions in oil and gas operations,including enhanced oil recovery (EOR) operations.

The aqueous compositions can comprise a borate-acid buffer and water.The borate-acid buffer can exhibit a capacity to buffer at a pH of from6.0 to 8.5 (e.g., a pH of from 6.5 to 7.5). In some cases, theborate-acid buffer can exhibit a capacity to buffer at a pH below thepoint of zero charge of a formation into which the composition will beinjected as part of an oil and gas operation. In certain embodiments,the water comprises hard water or hard brine. For example, in somecases, the water comprises at least 10 ppm at least 100 ppm, at least500 ppm, at least 1,000 ppm, or at least 5,000 ppm, or at least 10,000ppm of divalent metal ions chosen from Ca²⁺, Mg²⁺, Sr²⁺, Ba²⁺, andcombinations thereof. In certain cases, the water comprises from 100 ppmto 25,000 ppm of divalent metal ions chosen from Ca²⁺, Mg²⁺, Sr²⁺, Ba²⁺,and combinations thereof.

Optionally, the aqueous composition can further comprise additionalcomponents for use in oil and gas operations, such as a surfactant, apolymer, a co-solvent, a friction reducer, a gelling agent, acrosslinker, a breaker, a pH adjusting agent, a non-emulsifier agent, aniron control agent, a corrosion inhibitor, a scale inhibitor, a biocide,a clay stabilizing agent, a chelating agent, a proppant, a wettabilityalteration chemical, or any combination thereof.

In some embodiments, the composition can comprise a borate-acid buffer,a surfactant package, and water. The surfactant package can comprise aprimary surfactant and optionally one or more secondary surfactants. Theaqueous composition can have a total surfactant concentration of from0.10% to 5% by weight, based on the total weight of the aqueouscomposition.

In some embodiments, the composition can comprise a borate-acid buffer,a water-soluble-polymer, and water. The water-soluble polymer cancomprise, for example, a polyacrylamide or a biopolymer.

The aqueous compositions can be used in oil and gas operations includingenhanced oil recovery (EOR) operations (e.g., a polymer floodingoperation, a surfactant flooding operation, an AS flooding operation, anAP flooding operation, a SP flooding operation, an ASP floodingoperation, a conformance control operation, or any combination thereof).In some embodiments, the aqueous composition can be used in a fracturingoperation. In some embodiments, the aqueous composition can be used in astimulation operation, or any combination thereof.

For example, provided herein are methods for improving the recovery ofhydrocarbons from a subterranean formation containing the hydrocarbonstherewithin. These methods can comprise injecting an aqueous compositioncomprising (i) a borate-acid buffer, (ii) a surfactant package, awater-soluble polymer, or any combination thereof, and (iii) water intothe subterranean formation through a wellbore in fluid communicationwith the subterranean formation. The borate-acid buffer can exhibit acapacity to buffer at a pH of from 6.0 to 8.5.

Also provided are methods of fracturing a rock matrix of anunconventional subterranean formation. These methods can compriseinjecting an aqueous composition comprising (i) a borate-acid buffer,(ii) a surfactant package, a water-soluble polymer, or a combinationthereof, and (iii) water into the unconventional subterranean formationthrough a wellbore in fluid communication with a rock matrix of thesubterranean formation at a sufficient pressure to create or extend atleast one fracture in the rock matrix of the unconventional subterraneanformation.

Also provided are methods for stimulating a subterranean formation.These methods can comprise introducing an aqueous composition comprising(i) a borate-acid buffer, (ii) a surfactant package, a water-solublepolymer, or a combination thereof, and (iii) water into the subterraneanformation through a wellbore in fluid communication with thesubterranean formation; and allowing the aqueous composition to imbibeinto a rock matrix of the subterranean formation for a period of time.In some embodiments, these methods can further comprise producing fluidsfrom the subterranean formation through the wellbore.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 shows images of oil contact angle measurements made using oil-wetcarbonate samples immersed in high hardness brine (50,000 ppm TDS, withapproximately 12,000 ppm Mg²⁺ and Ca²⁺) for various periods of time.

FIG. 2 shows images of oil contact angle measurements made using oil-wetcarbonate samples immersed in a formulation that includes 0.9% Guerbetalkoxylated carboxylate, 1.2% olefin sulfonate, and 0.9% alkoxylatedC12-C22 alcohol in high hardness brine (50,000 ppm TDS, withapproximately 12,000 ppm Mg²⁺ and Ca²⁺) containing 2% sodium tetraborateand 1% acetic acid for various periods of time.

FIG. 3 is a plot showing emulsion phase behavior with Formulation C(without borate-acid buffer) with an example crude oil at 95° C.

FIG. 4 is a plot showing emulsion phase behavior with Formulation D(including 1% by weight borate-acid buffer) with an example crude oil at95° C.

FIG. 5 is a plot showing emulsion phase behavior with Formulation F(including 0.5% by weight borate-acid buffer) with an example crude oilat 95° C.

FIG. 6 is a plot showing the results of a coreflood study performedusing Formulation C. Slug Injection: SP slug including 0.15 pore volumeof Formulation C with 2000 ppm AMPS. Polymer drive included 1.85 porevolume ethoxylated alcohol surfactant and 3000 ppm AMPS. Coreproperties: Bentheimer Sandstone; 12″×2″ length (inches). Studyperformed at 95° C. and a flow rate of 2 ft/da.

FIG. 7 is a plot showing the results of a coreflood study performedusing Formulation D (including 1% by weight borate-acid buffer). SlugInjection: SP slug including 0.15 pore volume of Formulation D with 2000ppm AMPS. Polymer drive included 1.85 pore volume ethoxylated alcoholsurfactant and 3000 ppm AMPS. Core properties: Bentheimer Sandstone;12″×2″ length (inches). Study performed at 95° C. and a flow rate of 2ft/da.

FIG. 8 is a plot showing the results of a coreflood study performedusing Formulation F (including 0.5% by weight borate-acid buffer). SlugInjection: SP slug including 0.15 pore volume of Formulation F with 2000ppm AMPS. Polymer drive included 1.85 pore volume ethoxylated alcoholsurfactant and 3000 ppm AMPS. Core properties: Bentheimer Sandstone;12″×2″ length (inches). Study performed at 95° C. and a flow rate of 2ft/da.

FIG. 9 is a plot showing the effect of a 2% borate-acid buffer (insurfactant solution) on imbibition recovery.

FIG. 10 is a plot showing the effect of addition 2% borate-acid buffer(in surfactant solution) on IFT.

DETAILED DESCRIPTION

Definitions

Unless otherwise indicated, the abbreviations used herein have theirconventional meaning within the chemical and geophysical arts.

As used in this specification and the following claims, the terms“comprise” (as well as forms, derivatives, or variations thereof, suchas “comprising” and “comprises”) and “include” (as well as forms,derivatives, or variations thereof, such as “including” and “includes”)are inclusive (i.e., open-ended) and do not exclude additional elementsor steps. For example, the terms “comprise” and/or “comprising,” whenused in this specification, specify the presence of stated features,integers, steps, operations, elements, and/or components, but do notpreclude the presence or addition of one or more other features,integers, steps, operations, elements, components, and/or groupsthereof. Accordingly, these terms are intended to not only cover therecited element(s) or step(s), but may also include other elements orsteps not expressly recited. Furthermore, as used herein, the use of theterms “a” or “an” when used in conjunction with an element may mean“one,” but it is also consistent with the meaning of “one or more,” “atleast one,” and “one or more than one.” Therefore, an element precededby “a” or “an” does not, without more constraints, preclude theexistence of additional identical elements.

The use of the term “about” applies to all numeric values, whether ornot explicitly indicated. This term generally refers to a range ofnumbers that one of ordinary skill in the art would consider as areasonable amount of deviation to the recited numeric values (i.e.,having the equivalent function or result). For example, this term can beconstrued as including a deviation of ±10 percent of the given numericvalue provided such a deviation does not alter the end function orresult of the value. Therefore, a value of about 1% can be construed tobe a range from 0.9% to 1.1%. Furthermore, a range may be construed toinclude the start and the end of the range. For example, a range of 10%to 20% (i.e., range of 10%-20%) can includes 10% and also includes 20%,and includes percentages in between 10% and 20%, unless explicitlystated otherwise herein.

It is understood that when combinations, subsets, groups, etc. ofelements are disclosed (e.g., combinations of components in acomposition, or combinations of steps in a method), that while specificreference of each of the various individual and collective combinationsand permutations of these elements may not be explicitly disclosed, eachis specifically contemplated and described herein. By way of example, ifan item is described herein as including a component of type A, acomponent of type B, a component of type C, or any combination thereof,it is understood that this phrase describes all of the variousindividual and collective combinations and permutations of thesecomponents. For example, in some embodiments, the item described by thisphrase could include only a component of type A. In some embodiments,the item described by this phrase could include only a component of typeB. In some embodiments, the item described by this phrase could includeonly a component of type C. In some embodiments, the item described bythis phrase could include a component of type A and a component of typeB. In some embodiments, the item described by this phrase could includea component of type A and a component of type C. In some embodiments,the item described by this phrase could include a component of type Band a component of type C. In some embodiments, the item described bythis phrase could include a component of type A, a component of type B,and a component of type C. In some embodiments, the item described bythis phrase could include two or more components of type A (e.g., A1 andA2). In some embodiments, the item described by this phrase couldinclude two or more components of type B (e.g., B1 and B2). In someembodiments, the item described by this phrase could include two or morecomponents of type C (e.g., C1 and C2). In some embodiments, the itemdescribed by this phrase could include two or more of a first component(e.g., two or more components of type A (A1 and A2)), optionally one ormore of a second component (e.g., optionally one or more components oftype B), and optionally one or more of a third component (e.g.,optionally one or more components of type C). In some embodiments, theitem described by this phrase could include two or more of a firstcomponent (e.g., two or more components of type B (B1 and B2)),optionally one or more of a second component (e.g., optionally one ormore components of type A), and optionally one or more of a thirdcomponent (e.g., optionally one or more components of type C). In someembodiments, the item described by this phrase could include two or moreof a first component (e.g., two or more components of type C (C1 andC2)), optionally one or more of a second component (e.g., optionally oneor more components of type A), and optionally one or more of a thirdcomponent (e.g., optionally one or more components of type B). Thephrases “combinations thereof” and “any combinations thereof” are usedsynonymously herein.

“Hydrocarbon-bearing formation” or simply “formation” refers to the rockmatrix in which a wellbore may be drilled. For example, a formationrefers to a body of rock that is sufficiently distinctive and continuoussuch that it can be mapped. It should be appreciated that while the term“formation” generally refers to geologic formations of interest, thatthe term “formation,” as used herein, may, in some instances, includeany geologic points or volumes of interest (such as a survey area).

“Unconventional formation” is a subterranean hydrocarbon-bearingformation that generally requires intervention in order to recoverhydrocarbons from the reservoir at economic flow rates or volumes. Forexample, an unconventional formation includes reservoirs having anunconventional microstructure in which fractures are used to recoverhydrocarbons from the reservoir at sufficient flow rates or volumes(e.g., an unconventional reservoir generally needs to be fractured underpressure or have naturally occurring fractures in order to recoverhydrocarbons from the reservoir at sufficient flow rates or volumes).

In some embodiments, the unconventional formation can include areservoir having a permeability of less than 25 millidarcy (mD) (e.g.,20 mD or less, 15 mD or less, 10 mD or less, 5 mD or less, 1 mD or less,0.5 mD or less, 0.1 mD or less, 0.05 mD or less, 0.01 mD or less, 0.005mD or less, 0.001 mD or less, 0.0005 mD or less, 0.0001 mD or less,0.00005 mD or less, 0.00001 mD or less, 0.000005 mD or less, 0.000001 mDor less, or less). In some embodiments, the unconventional formation caninclude a reservoir having a permeability of at least 0.000001 mD (e.g.,at least 0.000005 mD, at least 0.00001 mD, 0.00005 mD, at least 0.0001mD, 0.0005 mD, 0.001 mD, at least 0.005 mD, at least 0.01 mD, at least0.05 mD, at least 0.1 mD, at least 0.5 mD, at least 1 mD, at least 5 mD,at least 10 mD, at least 15 mD, or at least 20 mD).

The unconventional formation can include a reservoir having apermeability ranging from any of the minimum values described above toany of the maximum values described above. For example, in someembodiments, the unconventional formation can include a reservoir havinga permeability of from 0.000001 mD to 25 mD (e.g., from 0.001 mD to 25mD, from 0.001 mD to 10 mD, from 0.01 mD to 10 mD, from 0.1 mD to 10 mD,from 0.001 mD to 5 mD, from 0.01 mD to 5 mD, or from 0.1 mD to 5 mD).

The formation may include faults, fractures (e.g., naturally occurringfractures, fractures created through hydraulic fracturing, etc.),geobodies, overburdens, underburdens, horizons, salts, salt welds, etc.The formation may be onshore, offshore (e.g., shallow water, deep water,etc.), etc. Furthermore, the formation may include hydrocarbons, such asliquid hydrocarbons (also known as oil or petroleum), gas hydrocarbons,a combination of liquid hydrocarbons and gas hydrocarbons (e.g.including gas condensate), etc.

The formation, the hydrocarbons, or both may also includenon-hydrocarbon items, such as pore space, connate water, brine, fluidsfrom enhanced oil recovery, etc. The formation may also be divided upinto one or more hydrocarbon zones, and hydrocarbons can be producedfrom each desired hydrocarbon zone.

The term formation may be used synonymously with the terms reservoir andsubsurface volume of interest. For example, in some embodiments, thereservoir may be, but is not limited to, a shale reservoir, a carbonatereservoir, a tight sandstone reservoir, a tight siltstone reservoir, agas hydrate reservoir, a coalbed methane reservoir, etc. Indeed, theterms “formation,” “reservoir,” “hydrocarbon,” and the like are notlimited to any description or configuration described herein.

“Wellbore” refers to a continuous hole for use in hydrocarbon recovery,including any openhole or uncased portion of the wellbore. For example,a wellbore may be a cylindrical hole drilled into the formation suchthat the wellbore is surrounded by the formation, including rocks,sands, sediments, etc. A wellbore may be used for injection. A wellboremay be used for production. A wellbore may be used for hydraulicfracturing of the formation. A wellbore even may be used for multiplepurposes, such as injection and production. The wellbore may havevertical, inclined, horizontal, or any combination of trajectories. Forexample, the wellbore may be a vertical wellbore, a horizontal wellbore,a multilateral wellbore, or slanted wellbore. The wellbore may include a“build section.” “Build section” refers to practically any section of awellbore where the deviation is changing. As an example, the deviationis changing when the wellbore is curving. The wellbore may include aplurality of components, such as, but not limited to, a casing, a liner,a tubing string, a heating element, a sensor, a packer, a screen, agravel pack, etc. The wellbore may also include equipment to controlfluid flow into the wellbore, control fluid flow out of the wellbore, orany combination thereof. For example, each wellbore may include awellhead, a BOP, chokes, valves, or other control devices. These controldevices may be located on the surface, under the surface (e.g., downholein the wellbore), or any combination thereof. The wellbore may alsoinclude at least one artificial lift device, such as, but not limitedto, an electrical submersible pump (ESP) or gas lift. Some non-limitingexamples of wellbores may be found in U.S. Patent ApplicationPublication No. 2014/0288909 and U.S. Patent Application Publication No.2016/0281494A1, each of which is incorporated by reference in itsentirety. The term wellbore is not limited to any description orconfiguration described herein. The term wellbore may be usedsynonymously with the terms borehole or well.

“Fracturing” is one way that hydrocarbons may be recovered (sometimesreferred to as produced) from the formation. For example, hydraulicfracturing may entail preparing a fracturing fluid and injecting thatfracturing fluid into the wellbore at a sufficient rate and pressure toopen existing fractures and/or create fractures in the formation. Thefractures permit hydrocarbons to flow more freely into the wellbore. Inthe hydraulic fracturing process, the fracturing fluid may be preparedon-site to include at least proppants. The proppants, such as sand orother particles, are meant to hold the fractures open so thathydrocarbons can more easily flow to the wellbore. The fracturing fluidand the proppants may be blended together using at least one blender.The fracturing fluid may also include other components in addition tothe proppants.

The wellbore and the formation proximate to the wellbore are in fluidcommunication (e.g., via perforations), and the fracturing fluid withthe proppants is injected into the wellbore through a wellhead of thewellbore using at least one pump (oftentimes called a fracturing pump).The fracturing fluid with the proppants is injected at a sufficient rateand pressure to open existing fractures and/or create fractures in thesubsurface volume of interest. As fractures become sufficiently wide toallow proppants to flow into those fractures, proppants in thefracturing fluid are deposited in those fractures during injection ofthe fracturing fluid. After the hydraulic fracturing process iscompleted, the fracturing fluid is removed by flowing or pumping it backout of the wellbore so that the fracturing fluid does not block the flowof hydrocarbons to the wellbore. The hydrocarbons will typically enterthe same wellbore from the formation and go up to the surface forfurther processing.

The equipment to be used in preparing and injecting the fracturing fluidmay be dependent on the components of the fracturing fluid, theproppants, the wellbore, the formation, etc. However, for simplicity,the term “fracturing apparatus” is meant to represent any tank(s),mixer(s), blender(s), pump(s), manifold(s), line(s), valve(s), fluid(s),fracturing fluid component(s), proppants, and other equipment andnon-equipment items related to preparing the fracturing fluid andinjecting the fracturing fluid.

Other hydrocarbon recovery processes may also be utilized to recover thehydrocarbons. Furthermore, those of ordinary skill in the art willappreciate that one hydrocarbon recovery process may also be used incombination with at least one other recovery process or subsequent to atleast one other recovery process. Moreover, hydrocarbon recoveryprocesses may also include stimulation or other treatments.

“Friction reducer,” as used herein, refers to a chemical additive thatalters fluid rheological properties to reduce friction created withinthe fluid as it flows through small-diameter tubulars or similarrestrictions (e.g., valves, pumps). Generally polymers, or similarfriction reducing agents, add viscosity to the fluid, which reduces theturbulence induced as the fluid flows. Reductions in fluid friction ofgreater than 50% are possible depending on the friction reducerutilized, which allows the injection fluid to be injected into awellbore at a much higher injection rate (e.g., between 60 to 100barrels per minute) and also lower pumping pressure during proppantinjection.

“Injection fluid,” as used herein, refers to any fluid which is injectedinto a reservoir via a well. The injection fluid may include one or moreof a surfactant, an acid, a polymer, a friction reducer, a gellingagent, a crosslinker, a scale inhibitor, a breaker, a pH adjustingagent, a non-emulsifier agent, an iron control agent, a corrosioninhibitor, a biocide, a clay stabilizing agent, a proppant, awettability alteration chemical, a co-solvent (e.g., a C1-C5 alcohol, oran alkoxylated C1-C5 alcohol), or any combination thereof, to increasethe efficacy of the injection fluid.

“Fracturing fluid,” as used herein, refers to an injection fluid that isinjected into the well under pressure in order to cause fracturingwithin a portion of the reservoir.

The term “interfacial tension” or “IFT” as used herein refers to thesurface tension between test oil and water of different salinitiescontaining a surfactant formulation at different concentrations.Typically, interfacial tensions are measured using a spinning droptensiometer or calculated from phase behavior experiments.

The term “proximate” is defined as “near”. If item A is proximate toitem B, then item A is near item B. For example, in some embodiments,item A may be in contact with item B. For example, in some embodiments,there may be at least one barrier between item A and item B such thatitem A and item B are near each other, but not in contact with eachother. The barrier may be a fluid barrier, a non-fluid barrier (e.g., astructural barrier), or any combination thereof. Both scenarios arecontemplated within the meaning of the term “proximate.”

The term “contacting” as used herein, refers to materials or compoundsbeing sufficiently close in proximity to react or interact. For example,in methods of contacting an unrefined petroleum material, ahydrocarbon-bearing formation, and/or a wellbore, the term “contacting”can include placing a compound (e.g., a surfactant) or an aqueouscomposition (e.g., chemical, surfactant or polymer) within ahydrocarbon-bearing formation using any suitable manner known in the art(e.g., pumping, injecting, pouring, releasing, displacing, spotting orcirculating the chemical into a well, wellbore or hydrocarbon-bearingformation).

The terms “unrefined petroleum” and “crude oil” are used interchangeablyand in keeping with the plain ordinary usage of those terms. “Unrefinedpetroleum” and “crude oil” may be found in a variety of petroleumreservoirs (also referred to herein as a “reservoir,” “oil fielddeposit” “deposit” and the like) and in a variety of forms includingoleaginous materials, oil shales (i.e., organic-rich fine-grainedsedimentary rock), tar sands, light oil deposits, heavy oil deposits,and the like. “Crude oils” or “unrefined petroleums” generally refer toa mixture of naturally occurring hydrocarbons that may be refined intodiesel, gasoline, heating oil, jet fuel, kerosene, and other productscalled fuels or petrochemicals. Crude oils or unrefined petroleums arenamed according to their contents and origins, and are classifiedaccording to their per unit weight (specific gravity). Heavier crudesgenerally yield more heat upon burning, but have lower gravity asdefined by the American Petroleum Institute (API) (i.e., API gravity)and market price in comparison to light (or sweet) crude oils. Crude oilmay also be characterized by its Equivalent Alkane Carbon Number (EACN).The term “API gravity” refers to the measure of how heavy or light apetroleum liquid is compared to water. If an oil's API gravity isgreater than 10, it is lighter and floats on water, whereas if it isless than 10, it is heavier and sinks. API gravity is thus an inversemeasure of the relative density of a petroleum liquid and the density ofwater. API gravity may also be used to compare the relative densities ofpetroleum liquids. For example, if one petroleum liquid floats onanother and is therefore less dense, it has a greater API gravity.

Crude oils vary widely in appearance and viscosity from field to field.They range in color, odor, and in the properties they contain. While allcrude oils are mostly hydrocarbons, the differences in properties,especially the variation in molecular structure, determine whether acrude oil is more or less easy to produce, pipeline, and refine. Thevariations may even influence its suitability for certain products andthe quality of those products. Crude oils are roughly classified intothree groups, according to the nature of the hydrocarbons they contain.(i) Paraffin-based crude oils contain higher molecular weight paraffins,which are solid at room temperature, but little or no asphaltic(bituminous) matter. They can produce high-grade lubricating oils. (ii)Asphaltene based crude oils contain large proportions of asphalticmatter, and little or no paraffin. Some are predominantly naphthenes andso yield lubricating oils that are sensitive to temperature changes thanthe paraffin-based crudes. (iii) Mixed based crude oils contain bothparaffin and naphthenes, as well as aromatic hydrocarbons. Most crudeoils fit this latter category.

“Reactive” crude oil, as referred to herein, is crude oil containingnatural organic acidic components (also referred to herein as unrefinedpetroleum acid) or their precursors such as esters or lactones. Thesereactive crude oils can generate soaps (carboxylates) when reacted withalkali. More terms used interchangeably for crude oil throughout thisdisclosure are hydrocarbons, hydrocarbon material, or active petroleummaterial. An “oil bank” or “oil cut” as referred to herein, is the crudeoil that does not contain the injected chemicals and is pushed by theinjected fluid during an enhanced oil recovery process. A “nonactiveoil,” as used herein, refers to an oil that is not substantiallyreactive or crude oil not containing significant amounts of naturalorganic acidic components or their precursors such as esters or lactonessuch that significant amounts of soaps are generated when reacted withalkali. A nonactive oil as referred to herein includes oils having anacid number of less than 0.5 mg KOH/g of oil.

“Unrefined petroleum acids” as referred to herein are carboxylic acidscontained in active petroleum material (reactive crude oil). Theunrefined petroleum acids contain C₁₁-C₂₀ alkyl chains, includingnapthenic acid mixtures. The recovery of such “reactive” oils may beperformed using alkali (e.g., NaOH or Na₂CO₃) in a surfactantcomposition. The alkali reacts with the acid in the reactive oil to formsoap in situ. These in situ generated soaps serve as a source ofsurfactants minimizing the levels of added surfactants, thus enablingefficient oil recovery from the reservoir.

The term “polymer” refers to a molecule having a structure thatessentially includes the multiple repetitions of units derived, actuallyor conceptually, from molecules of low relative molecular mass. In someembodiments, the polymer is an oligomer.

The term “productivity” as applied to a petroleum or oil well refers tothe capacity of a well to produce hydrocarbons (e.g., unrefinedpetroleum); that is, the ratio of the hydrocarbon flow rate to thepressure drop, where the pressure drop is the difference between theaverage reservoir pressure and the flowing bottom hole well pressure(i.e., flow per unit of driving force).

The term “oil solubilization ratio” is defined as the volume of oilsolubilized divided by the volume of surfactant in microemulsion. Allthe surfactant is presumed to be in the microemulsion phase. The oilsolubilization ratio is applied for Winsor type I and type III behavior.The volume of oil solubilized is found by reading the change betweeninitial aqueous level and excess oil (top) interface level. The oilsolubilization ratio is calculated as follows:

$\sigma_{o} = \frac{V_{o}}{V_{s}}$where σ_(o) is the oil solubilization ratio, V_(o) is the volume of oilsolubilized, and V_(s) is the volume of surfactant.

The term “water solubilization ratio” is defined as the volume of watersolubilized divided by the volume of surfactant in microemulsion. Allthe surfactant is presumed to be in the microemulsion phase. The watersolubilization ratio is applied for Winsor type III and type IIbehavior. The volume of water solubilized is found by reading the changebetween initial aqueous level and excess water (bottom) interface level.The water solubilization parameter is calculated as follows:

$\sigma_{w} = \frac{V_{w}}{V_{s}}$where σ_(w) is the water solubilization ratio, V_(w) is the volume ofoil solubilized, and V_(s) is the volume of surfactant.

The optimum solubilization ratio occurs where the oil and watersolubilization ratios are equal. The coarse nature of phase behaviorscreening often does not include a data point at optimum, so thesolubilization ratio curves are drawn for the oil and watersolubilization ratio data and the intersection of these two curves isdefined as the optimum. The following is true for the optimumsolubilization ratio:σ_(o)=σ_(w)=σ*where σ* is the optimum solubilization ratio.

The term “solubility” or “solubilization” in general refers to theproperty of a solute, which can be a solid, liquid or gas, to dissolvein a solid, liquid or gaseous solvent thereby forming a homogenoussolution of the solute in the solvent. Solubility occurs under dynamicequilibrium, which means that solubility results from the simultaneousand opposing processes of dissolution and phase joining (e.g.,precipitation of solids). The solubility equilibrium occurs when the twoprocesses proceed at a constant rate. The solubility of a given solutein a given solvent typically depends on temperature. For many solidsdissolved in liquid water, the solubility increases with temperature. Inliquid water at high temperatures, the solubility of ionic solutes tendsto decrease due to the change of properties and structure of liquidwater. In more particular, solubility and solubilization as referred toherein is the property of oil to dissolve in water and vice versa.

“Viscosity” refers to a fluid's internal resistance to flow or beingdeformed by shear or tensile stress. In other words, viscosity may bedefined as thickness or internal friction of a liquid. Thus, water is“thin”, having a lower viscosity, while oil is “thick”, having a higherviscosity. More generally, the less viscous a fluid is, the greater itsease of fluidity.

The term “salinity” as used herein, refers to concentration of saltdissolved in an aqueous phases. Examples for such salts are withoutlimitation, sodium chloride, magnesium and calcium sulfates, andbicarbonates. In more particular, the term salinity as it pertains tothe present invention refers to the concentration of salts in brine andsurfactant solutions.

The term “co-solvent,” as used herein, refers to a compound having theability to increase the solubility of a solute (e.g., a surfactant asdisclosed herein) in the presence of an unrefined petroleum acid. Insome embodiments, the co-solvents provided herein have a hydrophobicportion (alkyl or aryl chain), a hydrophilic portion (e.g., an alcohol)and optionally an alkoxy portion. Co-solvents as provided herein includealcohols (e.g., C₁-C₆ alcohols, C₁-C₆ diols), alkoxy alcohols (e.g.,C₁-C₆ alkoxy alcohols, C₁-C₆ alkoxy diols, and phenyl alkoxy alcohols),glycol ether, glycol and glycerol. The term “alcohol” is used accordingto its ordinary meaning and refers to an organic compound containing an—OH groups attached to a carbon atom. The term “diol” is used accordingto its ordinary meaning and refers to an organic compound containing two—OH groups attached to two different carbon atoms. The term “alkoxyalcohol” is used according to its ordinary meaning and refers to anorganic compound containing an alkoxy linker attached to a —OH group

The phrase “point of zero charge,” as used herein, refers to the pH atwhich the surface charge (i.e., zeta potential) of a solid material,such as the rock matrix in a subterranean reservoir, is zero.

Unless otherwise specified, all percentages are in weight percent andthe pressure is in atmospheres. The compositions and methods describedherein relate to compositions and methods described inPCT/US2018/044715, filed Jul. 31, 2018, filed Jul. 31, 2018 entitled“Injection Fluids Comprising Anionic Surfactants for TreatingUnconventional Formations”); PCT/US2018/044707, filed Jul. 31, 2018,filed Jul. 31, 2018 entitled “Injection Fluids Comprising Non-IonicSurfactants for Treating Unconventional Formations”); andPCT/US2018/044716, filed Jul. 31, 2018, filed Jul. 31, 2018 entitled“Injection Fluids for Stimulating Fractured Formations”), all of whichare hereby incorporated by reference.

Aqueous Compositions

Provided herien are aqueous compostions comprising a borate-acid buffer.In some embodiments, the composition can comprise a borate-acid bufferand water. In some embodiments, the composition can comprise aborate-acid buffer, a surfactant package, and water. In someembodiments, the composition can comprise a borate-acid buffer, apolymer, and water.

The water used to form the aqueous compositions can comprise any type ofwater, treated or untreated, and can vary in salt content. For example,the water can comprise sea water, brackish water, fresh water, flowbackor produced water, wastewater (e.g., reclaimed or recycled), riverwater, lake or pond water, aquifer water, brine (e.g., reservoir orsynthetic brine), or any combination thereof.

In some embodiments, the water can comprise hard water or hard brine.The hard water or hard brine comprises a divalent metal ion chosen fromCa²⁺, Mg²⁺, Sr²⁺, Ba²⁺, and combinations thereof. In certainembodiments, the hard water or hard brine can comprise at least 10 ppmat least 100 ppm, at least 500 ppm, at least 1,000 ppm, at least 5,000ppm, or at least 10,000 ppm of divalent metal ions chosen from Ca²⁺,Mg²⁺, Sr²⁺, Ba²⁺, and combinations thereof. In certain examples, thehard water or hard brine can comprise from 100 ppm to 25,000 ppm ofdivalent metal ions chosen from Ca²⁺, Mg²⁺, Sr²⁺, Ba²⁺, and combinationsthereof.

The borate-acid buffer serves to buffer the pH of the aqueouscomposition. The composition can be buffered such that a minimaladdition of an acid or base to the buffered composition will notsubstantially impact the pH of the composition. In some embodiments, theborate-acid buffer can exhibit a capacity to buffer at a pH of from atleast 6 (e.g., a pH of at least 6.25, a pH of at least 6.5, a pH. of atleast 6.75, a pH of at least 7, a pH of at least 7.25, a pH of at least7.5, a pH. of at least 7.75, a pH of at least 8, or a pH of at least8.25). In some embodiments, the borate-acid buffer can exhibit acapacity to buffer at a pH of 8.5 or less (e.g., a pH of 8.25 or less, apH of 8 or less, a pH of 7.75 or less, a pH of 7.5 or less, a pH of 7.25or less, a pH of 7 or less, a pH of 6.75 or less, a pH of 6.5 or less,or a pH of 6.25 or less).

The borate-acid buffer can exhibit a capacity to buffer at a pH rangingfrom any of the minimum values described above to any of the maximumvalues described above. For example, the borate-acid buffer can exhibita capacity to buffer at a pH of from 6 to 8.5 (e.g., from 6.5 to 7.5,from 6 to 7.5, from 6.5 to 7, or from 6 to 7).

In certain embodiments, the borate-acid buffer can exhibit a capacity tobuffer at a pH of less than 8. In certain embodiments, the borate-acidbuffer can exhibit a capacity to buffer at a pH of less than 7.

In some cases, the borate-acid buffer can exhibit a capacity to bufferat a pH below the point of zero charge of a formation into which thecomposition will be injected as part of an oil and gas operation.

In some embodiments, the aqueous composition can have a salinity of atleast 5,000 ppm. In other embodiments, the aqueous composition has asalinity of at least 50,000 ppm. In other embodiments, the aqueouscomposition has a salinity of at least 100,000 ppm. In otherembodiments, the aqueous composition has a salinity of at least 250,000ppm. The total range of salinity (total dissolved solids in the brine)is 100 ppm to saturated brine (about 260,000 ppm).

In some embodiments, the aqueous composition can have a temperature ofat least 20° C. (e.g., at least 30° C., at least 40° C., at least 50°C., at least 60° C., at least 70° C., at least 80° C., at least 90° C.,at least 100° C., or at least 110° C.). The aqueous composition can havea temperature of 120° C. or less (e.g., 110° C. or less, 100° C. orless, 90° C. or less, 80° C. or less, 70° C. or less, 60° C. or less,50° C. or less, 40° C. or less, or 30° C. or less). In some embodiments,the aqueous composition can have a temperature of greater than 120° C.

The aqueous composition can have a temperature ranging from any of theminimum values described above to any of the maximum values describedabove. For example, the aqueous composition can have a temperature offrom 20° C. to 120° C. (e.g., from 50° C. to 120° C., or from 80° C. to120° C.).

In some embodiments, the aqueous composition can have a viscosity ofbetween 20 mPas and 100 mPas at 20° C. The viscosity of the aqueoussolution may be increased from 0.3 mPas to 1, 2, 10, 20, 100 or even1000 mPas by including a water-soluble polymer. The apparent viscosityof the aqueous composition may be increased with a gas (e.g., a foamforming gas) as an alternative to the water-soluble polymer.

Borate-Acid Buffers

The aqueous composition described herein include a borate-acid buffer.

In some embodiments, the borate-acid buffer can comprise a boratecompound and a conjugate base of an acid.

A variety of suitable boron compounds may be used. Examples of boroncompounds include Borax, Sodium tetraborate decahydrate (Na₂B₄O₇·10H₂O),Borax pentahydrate (Na₂B₄O₇·5H₂O), Kernite (Na₂B₄O₇·4H₂O), Boraxmonohydrate (Na₂O·2B₂O₃·H₂O), Sodium metaborate tetrahydrate (NaB₂·4H₂Oor Na₂O·B₂O₃·8H₂O), Sodium metaborate dihydrate (NaBO₂·2H₂O orNa₂O·B₂O₃·4H₂O), Ezcurrite (2Na₂O·5.1B₂O₃·7H₂O), Auger's sodiumborate/Nasinite (2Na₂O·5B₂O₃·5H₂O), Sodium pentaborate(Na₂O·5B₂O₃·10H₂O), Potassium metaborate (K₂O·B₂O₃·2.5H₂O), Potassiumtetraborate (K₂O·2B₂O₃·8H₂O or 4H₂O), Auger's potassium pentaborate(2K₂O·5B₂O₃·5H₂O), Potassium pentaborate (K₂O·5B₂O₃·8H₂O), Lithiummetaborate octahydrate (LiBO₂·8H₂O or Li₂O·B₂O₃·16H₂O), Lithiumtetraborate trihydrate (Li₂O·2B₂O₃·3H₂O), Lithium pentaborate(Li₂O·5B₂O₃·10H₂O), Rubidium diborate (Rb₂O·2B₂H₂O), Rubidiumpentaborate (Rb₂O·5B₂O₃·8H₂O), Rubidium metaborate (Rb₂O·B₂O₃·3H₂O),Cesium Metaborate (Cs₂O·B₂O₃·7H₂O), Cesium diborate (Cs₂O·2B₂O₃·5H₂O),Cesium pentaborate (Cs₂O·5B₂O₃·8H₂O), Ammonium biborate((NH₄)₂·2B₂O₃·4H₂O), Ammonium pentaborate ((NH₄)₂O·5B₂O₃·8H₂O),Larderellite, probably ((NH₄)₂O·5B₂O₃·4H₂O), Ammonioborite((NH₄)₂O·5B₂O₃·5⅓H₂O), Kernite (Rasorite) (Na₂B₄O₂·4H₂O), Tincalconite(Mohavite) (Na₂B₄O₇·5H₂O), Borax (Tincal) (Na₂B₄O₇·10H₂O), Sborgite(Na₂B₁₀O₁₆·10H₂O), Ezcurrite (Na₄B₁₀O₁₇·7H₂O), Probertite (Kramerite)(NaCaB₅O₉·5H₂O), Ulxiete (Hayesine, Franklandite) (NaCaB₅O₉·8H₂O),Nobleite (CaB₆O₁₀·4H₂O), Gowerite (CaB₆O₁₀·5H₂O), Frolovite(Ca₂B₄O₈·7H₂O), Colemanite (Ca₂B₆O₁₁·5H₂O), Meyerhofferite(Ca₂B₆O₁₁·7H₂O), Inyoite (Ca₂B₆O₁₁·13H₂O), Priceite {(Pandermite)(Cryptomorphite)} (Ca₄B₁₀O₁₉·7H₂O), Tertschite (Ca₄B₁₀O₁₉·20H₂O),Ginorite (Ca₂B₁₄O₂₃·8H₂O), Pinnoite (MgB₂O₄·3H₂O), Paternoite(MgB₈O₁₃·4H₂O), Kurnakovite (Mg₂B₆O₁₁·15H₂O), Inderite (lesserite)(monoclinic) (Mg₂B₆O₁₁·15H₂O), Preobrazhenskite (Mg₃B₁₀O₁₈·4½H₂O),Hydroboracite (CaMgB₆O₁₁·6H₂O), Inderborite (CaMgB₆O₁₁·11H₂O),Kaliborite (Heintzite) (KMg₂B₁₁O₁₉·9H₂O), Larderellite((NH₄)₂B₁₀O₁₆·4H₂O), Ammonioborite ((NH₄)₂B₁₀O₁₆5⅓H₂O), Veatchite(SrB₆O₁₀·2H₂O), p-Veatchite ((Sr,Ca)B₆O₁₀·2H₂O), Teepleite(Na₂B₂O₄·2Na₂Cl·4H₂O), Bandylite (CuB₂O₄·CuCl₂·4H₂O), Hilgardite(monocline) (3Ca₂B₆O₁₁·2CaCl₂·4H₂O), Parahilgardite (triclinic)(3Ca₂B₆O₁₁·2CaCl₂·4H₂O), Boracite (Mg₅B₁₄O₂₆MgCl₂), Fluoborite(Mg₃(BO₃)(F,OH)₃), Hambergite (Be₂(BO₃)(OH)), Sussexite((Mn,Zn)(BO₂)(OH)), (Ascharite Camsellite) (Mg(BO₂)(OH)), Szaibelyite(Mg(BO₂)(OH)), Roweite ((Mn,Mg,Zn)Ca(BO₂)₂(OH)₂), Seamanite(Mn₃(PO₄)(BO₃)·3H₂O), Wiserite (Mn₄B₂O₅(OH,Cl)₄), Luneburgite(Mg₃B₂(OH)₆(PO₄)₂·6H₂O), Cahnite (Ca₂B(OH)₄(AsO₄)), Sulfoborite(Mg₆H₄(BO₃)₄(SO₄)₂·7H₂O), Johachidolite (H₆Na₂Ca₃Al₄F₅B₆O₂₀), BoricAcid, Sassolite (H₃BO₃), Jeremejewite (Eichwaldite) (AlBO₃), Kotoite(Mg₃(BO₃)₂), Nordenskioldine (CaSn(BO₃)₂), Rhodizite, Warwickite((Mg,Fe)₃TiB₂O₆), Ludwigite (Ferro-ludwegite, Vonsenite)((Mg,Fe^(II))₂Fe^(III)BO₅), Paigeite ((Fe^(II),Mg)₂Fe^(III)BO₅),Pinakiolite (Mg₃Mn^(II)Mn₂ ^(III)B₂O₁₀), Axinite(2Al₂O₃·2(Fe,Mn)O·4CaO·H₂O·B₂O₃8SiO₂), Bakerite, Danburite(CaO·B₂O₃·2SiO₂), Datolite (2CaO·H₂O·B₂O₃·SiO₂), Dumortierite(8Al₂O₃·H₂OB₂O₃·6SiO₂), Grandidierite(11(Al,Fe,B)₂O₃·7(Mg,Fe,Ca)O·2(H,Na,K)₂O·7SiO₂), Homilite(2CaO·FeO·B₂O₃·2SiO₂), Howlite (4CaO·5H₂O·5B₂O₃·2SiO₂), Hyalotekite(16(Pb,Ba,Ca)O·F·2B₂O₃·24H₂O), Kornerupine, Manandonite(7Al₂O₃·2Li₂O·12H₂O·2B₂O₃·6SiO₂), Sapphirine, Searlesite(Na₂O·2H₂O·B₂O₃·4SiO₂), Serendibite (3Al₂O₃·2Ca·4MgO·B₂O₃·4SiO₂), andany combination thereof.

In certain embodiments, in boron compound can comprise a metaborate or aborax. In certain embodiments, the boron compound can comprise sodiumtetraborate, calcium tetraborate, sodium borate, sodium metaborate, orany combination thereof. In embodiments, the boron compound comprisessodium metaborate. The term “sodium metaborate” as provided hereinrefers to the borate salt having the chemical formula NaBO₂4H₂O and inthe customary sense, refers to CAS Registry No. 10555-76-7. Inembodiments, the boron compound comprises borax. Other suitablecompounds include, for example, barium borate or zinc borate.

The acid can comprise any suitable acid. For example, the acid cancomprise acetic acid, citric acid, boric acid, tartaric acid,hydrochloric acid, succinic acid, or any combination thereof.

In some embodiments, the acid can comprise an organic acid. In someembodiment, the conjugate base of the acid comprises a chelator for adivalent metal ion (e.g., Mg²⁺ or Ca²⁺).

In some embodiments, the conjugate base of the acid comprises two ormore heteroatoms (e.g., two or more oxygen atoms). In certainembodiments, the conjugate base comprises one or more carboxylatemoieties. For example, the conjugate base can comprise acetate, citrate,tartrate, succinate, or any combination thereof.

The borate compound and the conjugate base of the organic acid can bepresent at a weight ratio of from 1:1 to 5:1 (e.g., from 1:1 to 3:1).

In some embodiments, the borate-acid buffer can comprise two or moredifferent borate compounds, two or more conjugate bases of differentacids, or any combination thereof. By way of illustration, theborate-acid buffer can be prepared by mixing two or more boratecompounds with an acid, a borate compound with two or more acids, or twoor more borate compounds with two or more acids.

In some embodiments, the borate-acid buffer comprises a borate compound,a conjugate base of a first acid, and a conjugate base of a second acid.In some cases, the first acid comprises acetic acid. In some cases, thesecond acid comprises an acid whose conjugate base has lower solubilityin the aqueous composition than acetate. For example, the second acidcan comprise citric acid.

In some embodiments, the borate-acid buffer can comprise a first boratecompound, second borate compounds, and a conjugate base of an acid.

One of ordinary skill in the art will recognize that the borate-acidbuffers described above can likewise be formed by combining boric acidwith an alkali.

For example, borate-acid buffers can be formed by combining boric acidan alkali such as an acetate salt (e.g., sodium acetate, potassiumacetate), a citrate salt (e.g., sodium citrate, potassium citrate), atartrate salt (e.g., sodium tartrate, potassium tartrate, sodiumpotassium tartrate, potassium bitartrate), a hydroxide salt (e.g.,sodium hydroxide, potassium hydroxide), a succinate salt (e.g., sodiumsuccinate, potassium succinate), or any combination thereof.

In these examples, the alkali can form a conjugate acid that comprises achelator for a divalent metal ion. In some cases, the conjugate acid cancomprise two or more heteroatoms (e.g., two or more oxygen atoms). Incertain cases, the conjugate acid can comprise one or more carboxylatemoieties.

The borate-acid buffer can have a concentration within the aqueouscomposition of at least 0.01% by weight (e.g., at least 0.02% by weight,at least 0.03% by weight, at least 0.04% by weight, at least 0.05% byweight, at least 0.06% by weight, at least 0.07% by weight, at least0.08% by weight, at least 0.09% by weight, at least 0.1% by weight, atleast 0.15% by weight, at least 0.2% by weight, at least 0.25% byweight, at least 0.3% by weight, at least 0.35% by weight, at least 0.4%by weight, at least 0.45% by weight, at least 0.5% by weight, at least0.55% by weight, at least 0.6% by weight, at least 0.65% by weight, atleast 0.7% by weight, at least 0.75% by weight, at least 0.8% by weight,at least 0.85% by weight, at least 0.9% by weight, at least 0.95% byweight, at least 1% by weight, at least 1.25% by weight, at least 1.5%by weight, at least 1.75% by weight, at least 2% by weight, at least2.5% by weight, at least 3% by weight, at least 3.5% by weight, at least4% by weight, or at least 4.5% by weight), based on the total weight ofthe aqueous composition. In some embodiments, the borate-acid buffer canhave a concentration within the aqueous composition of 5% by weight orless (e.g., 4.5% by weight or less, 4% by weight or less, 3.5% by weightor less, 3% by weight or less, 2.5% by weight or less, 2% by weight orless, 1.75% by weight or less, 1.5% by weight or less, 1.25% by weightor less, 1% by weight or less, 0.95% by weight or less, 0.9% by weightor less, 0.85% by weight or less, 0.8% by weight or less, 0.75% byweight or less, 0.7% by weight or less, 0.65% by weight or less, 0.6% byweight or less, 0.55% by weight or less, 0.5% by weight or less, 0.45%by weight or less, 0.4% by weight or less, 0.35% by weight or less, 0.3%by weight or less, 0.25% by weight or less, 0.2% by weight or less,0.15% by weight or less, 0.1% by weight or less, 0.09% by weight orless, 0.08% by weight or less, 0.07% by weight or less, 0.06% by weightor less, 0.05% by weight or less, 0.04% by weight or less, 0.03% byweight or less, or 0.02% by weight or less), based on the total weightof the aqueous composition.

The borate-acid buffer can have a concentration within the aqueouscomposition ranging from any of the minimum values described above toany of the maximum values described above. For example, in someembodiments, the borate-acid buffer can have a concentration within theaqueous composition of from 0.01% to 5% by weight (e.g., from 0.01% to2.5% by weight, from 0.01% to 2% by weight, from 0.05% to 5% by weight,from 0.05% to 2.5% by weight, from 0.05% to 1% by weight, or from 0.05%to 0.5% by weight), based on the total weight of the aqueouscomposition.

Surfactants and Surfactant Packages

In some embodiments, the aqueous composition can comprise a borate-acidbuffer, a surfactant package, and water. The surfactant package cancomprise a primary surfactant and optionally one or more secondarysurfactants.

The primary surfactant can have a concentration within the aqueouscomposition of at least 0.01% by weight (e.g., at least 0.02% by weight,at least 0.03% by weight, at least 0.04% by weight, at least 0.05% byweight, at least 0.06% by weight, at least 0.07% by weight, at least0.08% by weight, at least 0.09% by weight, at least 0.1% by weight, atleast 0.15% by weight, at least 0.2% by weight, at least 0.25% byweight, at least 0.3% by weight, at least 0.35% by weight, at least 0.4%by weight, at least 0.45% by weight, at least 0.5% by weight, at least0.55% by weight, at least 0.6% by weight, at least 0.65% by weight, atleast 0.7% by weight, at least 0.75% by weight, at least 0.8% by weight,at least 0.85% by weight, at least 0.9% by weight, at least 0.95% byweight, at least 1% by weight, at least 1.25% by weight, at least 1.5%by weight, at least 1.75% by weight, at least 2% by weight, at least2.5% by weight, at least 3% by weight, at least 3.5% by weight, at least4% by weight, or at least 4.5% by weight), based on the total weight ofthe aqueous composition. In some embodiments, the primary surfactant canhave a concentration within the aqueous composition of 5% by weight orless (e.g., 4.5% by weight or less, 4% by weight or less, 3.5% by weightor less, 3% by weight or less, 2.5% by weight or less, 2% by weight orless, 1.75% by weight or less, 1.5% by weight or less, 1.25% by weightor less, 1% by weight or less, 0.95% by weight or less, 0.9% by weightor less, 0.85% by weight or less, 0.8% by weight or less, 0.75% byweight or less, 0.7% by weight or less, 0.65% by weight or less, 0.6% byweight or less, 0.55% by weight or less, 0.5% by weight or less, 0.45%by weight or less, 0.4% by weight or less, 0.35% by weight or less, 0.3%by weight or less, 0.25% by weight or less, 0.2% by weight or less,0.15% by weight or less, 0.1% by weight or less, 0.09% by weight orless, 0.08% by weight or less, 0.07% by weight or less, 0.06% by weightor less, 0.05% by weight or less, 0.04% by weight or less, 0.03% byweight or less, or 0.02% by weight or less), based on the total weightof the aqueous composition. In particular embodiments, the primarysurfactant can have a concentration within the aqueous composition ofless than 1%, less than 0.5%, less than 0.2%, less than 0.1%, less than0.075%, or less than 0.05%.

The primary surfactant can have a concentration within the aqueouscomposition ranging from any of the minimum values described above toany of the maximum values described above. For example, in someembodiments, the primary surfactant can have a concentration within theaqueous composition of from 0.01% to 5% by weight (e.g., from 0.01% to2.5% by weight, from 0.05% to 5% by weight, from 0.05% to 2.5% byweight, from 0.05% to 1% by weight, or from 0.05% to 0.5% by weight),based on the total weight of the aqueous composition.

When present, the one or more secondary surfactants can have aconcentration within the aqueous composition of at least 0.01% by weight(e.g., at least 0.02% by weight, at least 0.03% by weight, at least0.04% by weight, at least 0.05% by weight, at least 0.06% by weight, atleast 0.07% by weight, at least 0.08% by weight, at least 0.09% byweight, at least 0.1% by weight, at least 0.15% by weight, at least 0.2%by weight, at least 0.25% by weight, at least 0.3% by weight, at least0.35% by weight, at least 0.4% by weight, at least 0.45% by weight, atleast 0.5% by weight, at least 0.55% by weight, at least 0.6% by weight,at least 0.65% by weight, at least 0.7% by weight, at least 0.75% byweight, at least 0.8% by weight, at least 0.85% by weight, at least 0.9%by weight, at least 0.95% by weight, at least 1% by weight, at least1.25% by weight, at least 1.5% by weight, at least 1.75% by weight, atleast 2% by weight, at least 2.5% by weight, at least 3% by weight, atleast 3.5% by weight, at least 4% by weight, or at least 4.5% byweight), based on the total weight of the aqueous composition. In someembodiments, the one or more secondary surfactants can have aconcentration within the aqueous composition of 5% by weight or less(e.g., 4.5% by weight or less, 4% by weight or less, 3.5% by weight orless, 3% by weight or less, 2.5% by weight or less, 2% by weight orless, 1.75% by weight or less, 1.5% by weight or less, 1.25% by weightor less, 1% by weight or less, 0.95% by weight or less, 0.9% by weightor less, 0.85% by weight or less, 0.8% by weight or less, 0.75% byweight or less, 0.7% by weight or less, 0.65% by weight or less, 0.6% byweight or less, 0.55% by weight or less, 0.5% by weight or less, 0.45%by weight or less, 0.4% by weight or less, 0.35% by weight or less, 0.3%by weight or less, 0.25% by weight or less, 0.2% by weight or less,0.15% by weight or less, 0.1% by weight or less, 0.09% by weight orless, 0.08% by weight or less, 0.07% by weight or less, 0.06% by weightor less, 0.05% by weight or less, 0.04% by weight or less, 0.03% byweight or less, or 0.02% by weight or less), based on the total weightof the aqueous composition. In particular embodiments, the one or moresecondary surfactants can have a concentration within the aqueouscomposition of less than 1%, less than 0.5%, less than 0.2%, less than0.1%, less than 0.075%, or less than 0.05%.

The one or more secondary surfactants can have a concentration withinthe aqueous composition ranging from any of the minimum values describedabove to any of the maximum values described above. For example, in someembodiments, the one or more secondary surfactants can have aconcentration within the aqueous composition of from 0.01% to 5% byweight (e.g., from 0.01% to 2.5% by weight, from 0.05% to 5% by weight,from 0.05% to 2.5% by weight, from 0.05% to 1% by weight, or from 0.05%to 0.5% by weight), based on the total weight of the aqueouscomposition.

In some embodiments, the primary surfactant and one or more secondarysurfactants can be present in the aqueous composition at a weight ratioof primary surfactant to one or more secondary surfactants of at least1:1 (e.g., at least 2:1, at least 2.5:1, at least 3:1, at least 4:1, atleast 5:1, at least 6:1, at least 7:1, at least 8:1, or at least 9:1).In some embodiments, the primary surfactant and one or more secondarysurfactants can be present in the aqueous composition in a weight ratioof primary surfactant to one or more secondary surfactants of 10:1 orless (e.g., 9:1 or less; 8:1 or less, 7:1 or less, 6:1 or less, 5:1 orless, 4:1 or less, 3:1 or less, 2.5:1 or less, or 2:1 or less).

The primary surfactant and one or more secondary surfactants can bepresent in the aqueous composition in a weight ratio ranging from any ofthe minimum values described above to any of the maximum valuesdescribed above. For example, the primary surfactant and one or moresecondary surfactants can be present in the aqueous composition in aweight ratio of primary surfactant to one or more secondary surfactantsof from 1:1 to 10:1 (e.g., 1:1 to 5:1).

In other embodiments, the one or more secondary surfactants are absent(i.e., the primary surfactant is the only surfactant present in theaqueous composition).

In some embodiments, the total concentration of all surfactants in theaqueous composition (the total concentration of the primary surfactantand the one or more secondary surfactants in the aqueous composition)can be at least 0.01% by weight (e.g., at least 0.02% by weight, atleast 0.03% by weight, at least 0.04% by weight, at least 0.05% byweight, at least 0.06% by weight, at least 0.07% by weight, at least0.08% by weight, at least 0.09% by weight, at least 0.1% by weight, atleast 0.15% by weight, at least 0.2% by weight, at least 0.25% byweight, at least 0.3% by weight, at least 0.35% by weight, at least 0.4%by weight, at least 0.45% by weight, at least 0.5% by weight, at least0.55% by weight, at least 0.6% by weight, at least 0.65% by weight, atleast 0.7% by weight, at least 0.75% by weight, at least 0.8% by weight,at least 0.85% by weight, at least 0.9% by weight, at least 0.95% byweight, at least 1% by weight, at least 1.25% by weight, at least 1.5%by weight, at least 1.75% by weight, at least 2% by weight, at least2.25% by weight, at least 2.5% by weight, at least 2.75% by weight, atleast 3% by weight, at least 3.25% by weight, at least 3.5% by weight,at least 3.75% by weight, at least 4% by weight, at least 4.25% byweight, at least 4.5% by weight, or at least 4.75% by weight), based onthe total weight of the aqueous composition. In some embodiments, thetotal concentration of all surfactants in the aqueous composition (thetotal concentration of the primary surfactant and the one or moresecondary surfactants in the aqueous composition) can be 5% by weight orless (e.g., 4.75% by weight or less, 4.5% by weight or less, 4.25% byweight or less, 4% by weight or less, 3.75% by weight or less, 3.5% byweight or less, 3.25% by weight or less, 3% by weight or less, 2.75% byweight or less, 2.5% by weight or less, 2.25% by weight or less, 2% byweight or less, 1.75% by weight or less, 1.5% by weight or less, 1.25%by weight or less, 1% by weight or less, 0.95% by weight or less, 0.9%by weight or less, 0.85% by weight or less, 0.8% by weight or less,0.75% by weight or less, 0.7% by weight or less, 0.65% by weight orless, 0.6% by weight or less, 0.55% by weight or less, 0.5% by weight orless, 0.45% by weight or less, 0.4% by weight or less, 0.35% by weightor less, 0.3% by weight or less, 0.25% by weight or less, 0.2% by weightor less, 0.15% by weight or less, 0.1% by weight or less, 0.09% byweight or less, 0.08% by weight or less, 0.07% by weight or less, 0.06%by weight or less, 0.05% by weight or less, 0.04% by weight or less,0.03% by weight or less, or 0.02% by weight or less), based on the totalweight of the aqueous composition.

The total concentration of all surfactants in the aqueous composition(the total concentration of the primary surfactant and the one or moresecondary surfactants in the aqueous composition) can range from any ofthe minimum values described above to any of the maximum valuesdescribed above. For example, in some embodiments, the totalconcentration of all surfactants in the aqueous composition (the totalconcentration of the primary surfactant and the one or more secondarysurfactants in the aqueous composition) can be from 0.01% by weight to5% by weight (e.g., from 0.01% to 2.5% by weight, from 0.01% to 1% byweight, or from 0.01% to 0.5% by weight).

The primary surfactant can comprise an anionic surfactant or a non-ionicsurfactant. The one or more secondary surfactants can comprise one ormore non-ionic surfactants, one or more anionic surfactants, one or morecationic surfactants, one or more zwitterionic surfactants, or anycombination thereof.

In some embodiments, the surfactant package can comprise an anionicsurfactant. In other embodiments, the surfactant package can consistessentially of an anionic surfactant (i.e., the anionic surfactant isthe only surfactant present in the surfactant package). In otherembodiments, the surfactant package can consist of an anionicsurfactant.

In some embodiments, the surfactant package can comprise a non-ionicsurfactant. In other embodiments, the surfactant package can consistessentially of a non-ionic surfactant (i.e., the non-ionic surfactant isthe only surfactant present in the surfactant package). In otherembodiments, the surfactant package can consist of a non-ionicsurfactant.

In some embodiments, the surfactant package can comprise an anionicsurfactant and a non-ionic surfactant. In other embodiments, thesurfactant package can consist essentially of an anionic surfactant anda non-ionic surfactant (i.e., the anionic surfactant and the non-ionicsurfactant are the only surfactants present in the surfactant package).In other embodiments, the surfactant package can consist of an anionicsurfactant and a non-ionic surfactant.

In some embodiments, the surfactant package can comprise an anionicsurfactant, a second anionic surfactant, and a non-ionic surfactant. Inother embodiments, the surfactant package can consist essentially of ananionic surfactant, a second anionic surfactant, and a non-ionicsurfactant (i.e., the anionic surfactant, the second anionic surfactant,and the non-ionic surfactant are the only surfactants present in thesurfactant package). In other embodiments, the surfactant package canconsist of an anionic surfactant, a second anionic surfactant, and anon-ionic surfactant.

Suitable anionic surfactants include a hydrophobic tail that comprisesfrom 6 to 60 carbon atoms. In some embodiments, the anionic surfactantcan include a hydrophobic tail that comprises at least 6 carbon atoms(e.g., at least 7 carbon atoms, at least 8 carbon atoms, at least 9carbon atoms, at least 10 carbon atoms, at least 11 carbon atoms, atleast 12 carbon atoms, at least 13 carbon atoms, at least 14 carbonatoms, at least 15 carbon atoms, at least 16 carbon atoms, at least 17carbon atoms, at least 18 carbon atoms, at least 19 carbon atoms, atleast 20 carbon atoms, at least 21 carbon atoms, at least 22 carbonatoms, at least 23 carbon atoms, at least 24 carbon atoms, at least 25carbon atoms, at least 26 carbon atoms, at least 27 carbon atoms, atleast 28 carbon atoms, at least 29 carbon atoms, at least 30 carbonatoms, at least 31 carbon atoms, at least 32 carbon atoms, at least 33carbon atoms, at least 34 carbon atoms, at least 35 carbon atoms, atleast 36 carbon atoms, at least 37 carbon atoms, at least 38 carbonatoms, at least 39 carbon atoms, at least 40 carbon atoms, at least 41carbon atoms, at least 42 carbon atoms, at least 43 carbon atoms, atleast 44 carbon atoms, at least 45 carbon atoms, at least 46 carbonatoms, at least 47 carbon atoms, at least 48 carbon atoms, at least 49carbon atoms, at least 50 carbon atoms, at least 51 carbon atoms, atleast 52 carbon atoms, at least 53 carbon atoms, at least 54 carbonatoms, at least 55 carbon atoms, at least 56 carbon atoms, at least 57carbon atoms, at least 58 carbon atoms, or at least 59 carbon atoms). Insome embodiments, the anionic surfactant can include a hydrophobic tailthat comprises 60 carbon atoms or less (e.g., 59 carbon atoms or less,58 carbon atoms or less, 57 carbon atoms or less, 56 carbon atoms orless, 55 carbon atoms or less, 54 carbon atoms or less, 53 carbon atomsor less, 52 carbon atoms or less, 51 carbon atoms or less, 50 carbonatoms or less, 49 carbon atoms or less, 48 carbon atoms or less, 47carbon atoms or less, 46 carbon atoms or less, 45 carbon atoms or less,44 carbon atoms or less, 43 carbon atoms or less, 42 carbon atoms orless, 41 carbon atoms or less, 40 carbon atoms or less, 39 carbon atomsor less, 38 carbon atoms or less, 37 carbon atoms or less, 36 carbonatoms or less, 35 carbon atoms or less, 34 carbon atoms or less, 33carbon atoms or less, 32 carbon atoms or less, 31 carbon atoms or less,30 carbon atoms or less, 29 carbon atoms or less, 28 carbon atoms orless, 27 carbon atoms or less, 26 carbon atoms or less, 25 carbon atomsor less, 24 carbon atoms or less, 23 carbon atoms or less, 22 carbonatoms or less, 21 carbon atoms or less, 20 carbon atoms or less, 19carbon atoms or less, 18 carbon atoms or less, 17 carbon atoms or less,16 carbon atoms or less, 15 carbon atoms or less, 14 carbon atoms orless, 13 carbon atoms or less, 12 carbon atoms or less, 11 carbon atomsor less, 10 carbon atoms or less, 9 carbon atoms or less, 8 carbon atomsor less, or 7 carbon atoms or less).

The anionic surfactant can include a hydrophobic tail that comprises anumber of carbon atoms ranging from any of the minimum values describedabove to any of the maximum values described above. For example, in someembodiments, the anionic surfactant can comprise a hydrophobic tailcomprising from 6 to 15, from 16 to 30, from 31 to 45, from 46 to 60,from 6 to 25, from 26 to 60, from 6 to 30, from 31 to 60, from 6 to 32,from 33 to 60, from 6 to 12, from 13 to 22, from 23 to 32, from 33 to42, from 43 to 52, from 53 to 60, from 6 to 10, from 10 to 15, from 16to 25, from 26 to 35, or from 36 to 45 carbon atoms. The hydrophobic(lipophilic) carbon tail may be a straight chain, branched chain, and/ormay comprise cyclic structures. The hydrophobic carbon tail may comprisesingle bonds, double bonds, triple bonds, or any combination thereof. Insome embodiments, the anionic surfactant can include a branchedhydrophobic tail derived from Guerbet alcohols. The hydrophilic portionof the anionic surfactant can comprise, for example, one or more sulfatemoieties (e.g., one, two, or three sulfate moieties), one or moresulfonate moieties (e.g., one, two, or three sulfonate moieties), one ormore sulfosuccinate moieties (e.g., one, two, or three sulfosuccinatemoieties), one or more carboxylate moieties (e.g., one, two, or threecarboxylate moieties), or any combination thereof.

In some embodiments, the anionic surfactant can comprise, for example asulfonate, a disulfonate, a polysulfonate, a sulfate, a disulfate, apolysulfate, a sulfosuccinate, a disulfosuccinate, a polysulfosuccinate,a carboxylate, a dicarboxylate, a polycarboxylate, or any combinationthereof. In some examples, the anionic surfactant can comprise aninternal olefin sulfonate (IOS), an isomerized olefin sulfonate, an alfaolefin sulfonate (AOS), an alkyl aryl sulfonate (AAS), a xylenesulfonate, an alkane sulfonate, a petroleum sulfonate, an alkyl diphenyloxide (di)sulfonate, an alcohol sulfate, an alkoxy sulfate, an alkoxysulfonate, an alkoxy carboxylate, an alcohol phosphate, or an alkoxyphosphate. In some embodiments, the anionic surfactant can comprise analkoxy carboxylate surfactant, an alkoxy sulfate surfactant, an alkoxysulfonate surfactant, an alkyl sulfonate surfactant, an aryl sulfonatesurfactant, or an olefin sulfonate surfactant.

An “alkoxy carboxylate surfactant” or “alkoxy carboxylate” refers to acompound having an alkyl or aryl attached to one or more alkoxylenegroups (typically —CH₂—CH(ethyl)-O—, —CH₂—CH(methyl)-O—, or —CH₂—CH₂—O—)which, in turn is attached to —COO— or acid or salt thereof includingmetal cations such as sodium. In embodiments, the alkoxy carboxylatesurfactant can be defined by the formulae below:

wherein R¹ is substituted or unsubstituted C6-C36 alkyl or substitutedor unsubstituted aryl; R² is, independently for each occurrence withinthe compound, hydrogen or unsubstituted C1-C6 alkyl; R³ is independentlyhydrogen or unsubstituted C1-C6 alkyl, n is an integer from 0 to 175, zis an integer from 1 to 6 and M⁺ is a monovalent, divalent or trivalentcation. In some of these embodiments, R¹ can be an unsubstituted linearor branched C6-C36 alkyl.

In certain embodiments, the alkoxy carboxylate can be aC6-C32:PO(0-65):EO(0-100)-carboxylate (i.e., a C6-C32 hydrophobic tail,such as a branched or unbranched C6-C32 alkyl group, attached to from 0to 65 propyleneoxy groups (—CH₂—CH(methyl)-O— linkers), attached in turnto from 0 to 100 ethyleneoxy groups (—CH₂—CH₂O— linkers), attached inturn to —COO⁻ or an acid or salt thereof including metal cations such assodium). In certain embodiments, the alkoxy carboxylate can be abranched or unbranched C6-C30:PO(30-40):EO(25-35)-carboxylate. Incertain embodiments, the alkoxy carboxylate can be a branched orunbranched C6-C12:PO(30-40):EO(25-35)-carboxylate. In certainembodiments, the alkoxy carboxylate can be a branched or unbranchedC6-C30:EO(8-30)-carboxylate.

An “alkoxy sulfate surfactant” or “alkoxy sulfate” refers to asurfactant having an alkyl or aryl attached to one or more alkoxylenegroups (typically —CH₂—CH(ethyl)-O—, —CH₂—CH(methyl)-O—, or —CH₂—CH₂—O—)which, in turn is attached to —SO₃ ⁻ or acid or salt thereof includingmetal cations such as sodium. In some embodiment, the alkoxy sulfatesurfactant has the formula R—(BO)_(e)—(PO)_(f)-(EO)_(g)—SO₃ ⁻ or acid orsalt (including metal cations such as sodium) thereof, wherein R isC6-C32 alkyl, BO is —CH₂—CH(ethyl)-O—, PO is —CH₂—CH(methyl)-O—, and EOis —CH₂—CH₂—O—. The symbols e, f and g are integers from 0 to 50 whereinat least one is not zero.

In embodiments, the alkoxy sulfate surfactant can be an aryl alkoxysulfate surfactant. The aryl alkoxy surfactant can be an alkoxysurfactant having an aryl attached to one or more alkoxylene groups(typically —CH₂—CH(ethyl)-O—, —CH₂—CH(methyl)-O—, or —CH₂—CH₂—O—) which,in turn is attached to —SO₃ ⁻ or acid or salt thereof including metalcations such as sodium.

An “alkyl sulfonate surfactant” or “alkyl sulfonate” refers to acompound that includes an alkyl group (e.g., a branched or unbranchedC6-C32 alkyl group) attached to —SO₃ ⁻ or acid or salt thereof includingmetal cations such as sodium.

An “aryl sulfate surfactant” or “aryl sulfate” refers to a compoundhaving an aryl group attached to —O—SO₃ ⁻ or acid or salt thereofincluding metal cations such as sodium. An “aryl sulfonate surfactant”or “aryl sulfonate” refers to a compound having an aryl group attachedto —SO₃ ⁻ or acid or salt thereof including metal cations such assodium. In some cases, the aryl group can be substituted, for example,with an alkyl group (an alkyl aryl sulfonate).

An “internal olefin sulfonate,” “isomerized olefin sulfonate,” or “IOS”refers to an unsaturated hydrocarbon compound comprising at least onecarbon-carbon double bond and at least one SO₃ ⁻ group, or a saltthereof. As used herein, a “C20-C28 internal olefin sulfonate,” “aC20-C28 isomerized olefin sulfonate,” or “C20-C28 IOS” refers to an IOS,or a mixture of IOSs with an average carbon number of 20 to 28, or of 23to 25. The C20-C28 IOS may comprise at least 80% of IOS with carbonnumbers of 20 to 28, at least 90% of IOS with carbon numbers of 20 to28, or at least 99% of IOS with carbon numbers of 20 to 28. As usedherein, a “C15-C18 internal olefin sulfonate,” “C15-C18 isomerizedolefin sulfonate,” or “C15-C18 IOS” refers to an IOS or a mixture ofIOSs with an average carbon number of 15 to 18, or of 16 to 17. TheC15-C18 IOS may comprise at least 80% of IOS with carbon numbers of 15to 18, at least 90% of IOS with carbon numbers of 15 to 18, or at least99% of IOS with carbon numbers of 15 to 18. The internal olefinsulfonates or isomerized olefin sulfonates may be alpha olefinsulfonates, such as an isomerized alpha olefin sulfonate. The internalolefin sulfonates or isomerized olefin sulfonates may also comprisebranching. In certain embodiments, C15-18 IOS may be added to thesurfactant package when the LPS injection fluid is intended for use inhigh temperature unconventional subterranean formations, such asformations above 130° F. (approximately 55° C.). The IOS may be at least20% branching, 30% branching, 40% branching, 50% branching, 60%branching, or 65% branching. In some embodiments, the branching isbetween 20-98%, 30-90%, 40-80%, or around 65%. Examples of internalolefin sulfonates and the methods to make them are found in U.S. Pat.No. 5,488,148, U.S. Patent Application Publication 2009/0112014, and SPE129766, all incorporated herein by reference.

In embodiments, the anionic surfactant can be a disulfonate,alkyldiphenyloxide disulfonate, mono alkyldiphenyloxide disulfonate, dialkyldiphenyloxide disulfonate, or a di alkyldiphenyloxidemonosulfonate, where the alkyl group can be a C6-C36 linear or branchedalkyl group. In embodiments, the anionic surfactant can be analkylbenzene sulfonate or a dibenzene disufonate. In embodiments, theanionic surfactant can be benzenesulfonic acid,decyl(sulfophenoxy)-disodium salt; linear or branched C6-C36alkyl:PO(0-65):EO(0-100) sulfate; or linear or branched C6-C36alkyl:PO(0-65):EO(0-100) carboxylate. In embodiments, the anionicsurfactant is an isomerized olefin sulfonate (C6-C30), internal olefinsulfonate (C6-C30) or internal olefin disulfonate (C6-C30). In someembodiments, the anionic surfactant is a Guerbet-PO(0-65)-EO(0-100)sulfate (Guerbet portion can be C6-C36). In some embodiments, theanionic surfactant is a Guerbet-PO(0-65)-EO(0-100) carboxylate (Guerbetportion can be C6-C36). In some embodiments, the anionic surfactant isalkyl PO(0-65) and EO(0-100) sulfonate: where the alkyl group is linearor branched C6-C36. In some embodiments, the anionic surfactant is asulfosuccinate, such as a dialkylsulfosuccinate. In some embodiments,the anionic surfactant is an alkyl aryl sulfonate (AAS) (e.g. an alkylbenzene sulfonate (ABS)), a C10-C30 internal olefin sulfate (IOS), apetroleum sulfonate, or an alkyl diphenyl oxide (di) sulfonate.

In some examples, the anionic surfactant can comprise a surfactantdefined by the formula below:R¹—R²—R³wherein R¹ comprises a branched or unbranched, saturated or unsaturated,cyclic or non-cyclic, hydrophobic carbon chain having 6-32 carbon atomsand an oxygen atom linking R¹ and R²; R² comprises an alkoxylated chaincomprising at least one oxide group selected from the group consistingof ethylene oxide, propylene oxide, butylene oxide, and combinationsthereof; and R³ comprises a branched or unbranched hydrocarbon chaincomprising 2-12 carbon atoms and from 2 to 5 carboxylate groups.

In some examples, the anionic surfactant can comprise a surfactantdefined by the formula below:

wherein R⁴ is, individually for each occurrence, a branched orunbranched, saturated or unsaturated, cyclic or non-cyclic, hydrophobiccarbon chain having 6-32 carbon atoms; and M represents a counterion(e.g., Na⁺, K⁺). In some embodiments, R⁴ is a branched or unbranched,saturated or unsaturated, cyclic or non-cyclic, hydrophobic carbon chainhaving 6-16 carbon atoms.

Suitable non-ionic surfactants include compounds that can be added toincrease wettability. In embodiments, the hydrophilic-lipophilic balance(HLB) of the non-ionic surfactant is greater than 10 (e.g., greater than9, greater than 8, or greater than 7). In some embodiments, the HLB ofthe non-ionic surfactant is from 7 to 10.

The non-ionic surfactant can comprise a hydrophobic tail comprising from6 to 60 carbon atoms. In some embodiments, the non-ionic surfactant caninclude a hydrophobic tail that comprises at least 6 carbon atoms (e.g.,at least 7 carbon atoms, at least 8 carbon atoms, at least 9 carbonatoms, at least 10 carbon atoms, at least 11 carbon atoms, at least 12carbon atoms, at least 13 carbon atoms, at least 14 carbon atoms, atleast 15 carbon atoms, at least 16 carbon atoms, at least 17 carbonatoms, at least 18 carbon atoms, at least 19 carbon atoms, at least 20carbon atoms, at least 21 carbon atoms, at least 22 carbon atoms, atleast 23 carbon atoms, at least 24 carbon atoms, at least 25 carbonatoms, at least 26 carbon atoms, at least 27 carbon atoms, at least 28carbon atoms, at least 29 carbon atoms, at least 30 carbon atoms, atleast 31 carbon atoms, at least 32 carbon atoms, at least 33 carbonatoms, at least 34 carbon atoms, at least 35 carbon atoms, at least 36carbon atoms, at least 37 carbon atoms, at least 38 carbon atoms, atleast 39 carbon atoms, at least 40 carbon atoms, at least 41 carbonatoms, at least 42 carbon atoms, at least 43 carbon atoms, at least 44carbon atoms, at least 45 carbon atoms, at least 46 carbon atoms, atleast 47 carbon atoms, at least 48 carbon atoms, at least 49 carbonatoms, at least 50 carbon atoms, at least 51 carbon atoms, at least 52carbon atoms, at least 53 carbon atoms, at least 54 carbon atoms, atleast 55 carbon atoms, at least 56 carbon atoms, at least 57 carbonatoms, at least 58 carbon atoms, or at least 59 carbon atoms). In someembodiments, the non-ionic surfactant can include a hydrophobic tailthat comprises 60 carbon atoms or less (e.g., 59 carbon atoms or less,58 carbon atoms or less, 57 carbon atoms or less, 56 carbon atoms orless, 55 carbon atoms or less, 54 carbon atoms or less, 53 carbon atomsor less, 52 carbon atoms or less, 51 carbon atoms or less, 50 carbonatoms or less, 49 carbon atoms or less, 48 carbon atoms or less, 47carbon atoms or less, 46 carbon atoms or less, 45 carbon atoms or less,44 carbon atoms or less, 43 carbon atoms or less, 42 carbon atoms orless, 41 carbon atoms or less, 40 carbon atoms or less, 39 carbon atomsor less, 38 carbon atoms or less, 37 carbon atoms or less, 36 carbonatoms or less, 35 carbon atoms or less, 34 carbon atoms or less, 33carbon atoms or less, 32 carbon atoms or less, 31 carbon atoms or less,30 carbon atoms or less, 29 carbon atoms or less, 28 carbon atoms orless, 27 carbon atoms or less, 26 carbon atoms or less, 25 carbon atomsor less, 24 carbon atoms or less, 23 carbon atoms or less, 22 carbonatoms or less, 21 carbon atoms or less, 20 carbon atoms or less, 19carbon atoms or less, 18 carbon atoms or less, 17 carbon atoms or less,16 carbon atoms or less, 15 carbon atoms or less, 14 carbon atoms orless, 13 carbon atoms or less, 12 carbon atoms or less, 11 carbon atomsor less, 10 carbon atoms or less, 9 carbon atoms or less, 8 carbon atomsor less, or 7 carbon atoms or less).

The non-ionic surfactant can include a hydrophobic tail that comprises anumber of carbon atoms ranging from any of the minimum values describedabove to any of the maximum values described above. For example, thenon-ionic surfactant can comprise a hydrophobic tail comprising from 6to 15, from 16 to 30, from 31 to 45, from 46 to 60, from 6 to 25, from26 to 60, from 6 to 30, from 31 to 60, from 6 to 32, from 33 to 60, from6 to 12, from 13 to 22, from 23 to 32, from 33 to 42, from 43 to 52,from 53 to 60, from 6 to 10, from 10 to 15, from 16 to 25, from 26 to35, or from 36 to 45 carbon atoms. In some cases, the hydrophobic tailmay be a straight chain, branched chain, and/or may comprise cyclicstructures. The hydrophobic carbon tail may comprise single bonds,double bonds, triple bonds, or any combination thereof. In some cases,the hydrophobic tail can comprise an alkyl group, with or without anaromatic ring (e.g., a phenyl ring) attached to it. In some embodiments,the hydrophobic tail can comprise a branched hydrophobic tail derivedfrom Guerbet alcohols.

Example non-ionic surfactants include alkyl aryl alkoxy alcohols, alkylalkoxy alcohols, or any combination thereof. In embodiments, thenon-ionic surfactant may be a mix of surfactants with different lengthlipophilic tail chain lengths. For example, the non-ionic surfactant maybe C9-C11:9EO, which indicates a mixture of non-ionic surfactants thathave a lipophilic tail length of 9 carbon to 11 carbon, which isfollowed by a chain of 9 EOs. The hydrophilic moiety is an alkyleneoxychain (e.g., an ethoxy (EO), butoxy (BO) and/or propoxy (PO) chain withtwo or more repeating units of EO, BO, and/or PO). In some embodiments,1-100 repeating units of EO are present. In some embodiments, 0-65repeating units of PO are present. In some embodiments, 0-25 repeatingunits of BO are present. For example, the non-ionic surfactant couldcomprise 10EO:5PO or 5EO. In embodiments, the non-ionic surfactant maybe a mix of surfactants with different length lipophilic tail chainlengths. For example, the non-ionic surfactant may be C9-C11:PO9:EO2,which indicates a mixture of non-ionic surfactants that have alipophilic tail length of 9 carbon to 11 carbon, which is followed by achain of 9 POs and 2 EOs. In specific embodiments, the non-ionicsurfactant is linear C9-C11:9EO. In some embodiments, the non-ionicsurfactant is a Guerbet PO(0-65) and EO(0-100) (Guerbet can be C6-C36);or alkyl PO(0-65) and EO(0-100): where the alkyl group is linear orbranched C1-C36. In some examples, the non-ionic surfactant can comprisea branched or unbranched C6-C32:PO(0-65):EO(0-100) (e.g., a branched orunbranched C6-C30:PO(30-40):EO(25-35), a branched or unbranchedC6-C12:PO(30-40):EO(25-35), a branched or unbranched C6-30:EO(8-30), orany combination thereof). In some embodiments, the non-ionic surfactantis one or more alkyl polyglucosides.

Example cationic surfactants include surfactant analogous to thosedescribed above, except bearing primary, secondary, or tertiary amines,or quaternary ammonium cations, as a hydrophilic head group.“Zwitterionic” or “zwitterion” as used herein refers to a neutralmolecule with a positive (or cationic) and a negative (or anionic)electrical charge at different locations within the same molecule.Example zwitterionic surfactants include betains and sultains.

Examples of suitable surfactants are disclosed, for example, in U.S.Pat. Nos. 3,811,504, 3,811,505, 3,811,507, 3,890,239, 4,463,806,6,022,843, 6,225,267, 7,629,299, 7,770,641, 9,976,072, 8,211, 837,9,422,469, 9,605,198, and 9,617,464; WIPO Patent Application Nos.WO/2008/079855, WO/2012/027757 and WO /2011/094442; as well as U.S.Patent Application Nos. 2005/0199395, 2006/0185845, 2006/0189486,2009/0270281, 2011/0046024, 2011/0100402, 2011/0190175, 2007/0191633,2010/004843. 2011/0201531, 2011/0190174, 2011/0071057, 2011/0059873,2011/0059872, 2011/0048721, 2010/0319920, 2010/0292110, and2017/0198202, each of which is hereby incorporated by reference hereinin its entirety for its description of example surfactants.

In some embodiments, the surfactant package (and by extension theaqueous composition) can comprise a non-ionic surfactant and an anionicsurfactant (e.g., a sulfonate or disulfonate). In some embodiments, thesurfactant package (and by extension the aqueous composition) cancomprise a non-ionic surfactant and two or more anionic surfactants(e.g., a sulfonate or disulfonate and a carboxylate). In someembodiments, the surfactant package (and by extension the aqueouscomposition) can comprise a non-ionic surfactant (e.g., a C6-C16 alkylphenol ethoxylate, or a C6-C16:PO(0-25):EO(0-25), such as a C9-C11ethoxylated alcohol, a C13 ethoxylated alcohol, a C6-C10 ethoxylatedpropoxylated alcohol, or a C10-C14 ethoxylated Guerbet alcohol) and asulfonate surfactant (e.g., a C10-16 disulfonate, or a C16-28 IOS). Insome embodiments, the surfactant package (and by extension the aqueouscomposition) can comprise a non-ionic surfactant (e.g., a C6-C16 alkylphenol ethoxylate, or a C6-16:PO(0-25):EO(0-25), such as a C9-C11ethoxylated alcohol, a C13 ethoxylated alcohol, a C6-C10 ethoxylatedpropoxylated alcohol, or a C10-C14 ethoxylated Guerbet alcohol), asulfonate surfactant (e.g., a C10-16 disulfonate, or a C16-28 IOS), anda carboxylate surfactant (e.g., a C10-16 alkyl polyglucoside carboxylateor a C22-C36 Guerbet alkoxylated carboxylate).

Specific example embodiments include aqueous compositions comprising thesurfactant packages in the table below.

Surfactants and Co-Solvents in Aqueous Composition Example (in weightpercent) 1 0.09% alkoxylated C6-C16 alcohol 0.06% disulfonate 2 0.1%alkoxylated C6-C16 alcohol 0.1% carboxylate 0.1% disulfonate 3 0.15%alkoxylated C6-C16 alcohol 0.075% carboxylate 0.075% disulfonate 4 0.2%alkoxylated C6-C16 alcohol 0.1% carboxylate 5 0.2% alkoxylated C6-C16alcohol 0.033% carboxylate 0.066% disulfonate 6 0.2% alkoxylated C6-C16alcohol 0.033% carboxylate 0.066% disulfonate 7 0.2% alkoxylated C6-C16alcohol 0.05% carboxylate 0.05% olefin sulfonate 8 0.15% alkoxylatedC6-C16 alcohol 0.05% carboxylate 0.05% olefin sulfonate 0.05% alkylpolyglucoside 9 0.1% alkoxylated C6-C16 alcohol 0.05% carboxylate 0.05%olefin sulfonate 0.1% alkyl polyglucoside 10 0.15% alkoxylated C6-C16alcohol 0.07% carboxylate 0.03% olefin sulfonate 0.1% alkylpolyglucoside 11 0.1% alkoxylated C6-C16 alcohol 0.04% carboxylate 0.05%olefin sulfonate 0.03% disulfonate 0.1% alkyl polyglucoside 12 0.1%alkoxylated C6-C16 alcohol 0.04% carboxylate 0.06% disulfonate 0.1%alkyl polyglucoside 13 0.15% alkoxylated C6-C16 alcohol 0.15%alkoxylated alkylphenol 0.1% olefin sulfonate 0.1% Guerbet alkoxylatedcarboxylate 14 0.125% alkoxylated C6-C16 alcohol 0.175% alkoxylatedalkylphenol 0.1% olefin sulfonate 0.1% Guerbet alkoxylated carboxylate15 0.1% alkoxylated C6-C16 alcohol 0.2% alkoxylated alkylphenol 0.1%olefin sulfonate 0.1% Guerbet alkoxylated carboxylate 16 0.12%alkoxylated C6-C16 alcohol 0.22% alkoxylated alkylphenol 0.08% olefinsulfonate 0.08% Guerbet alkoxylated carboxylate 17 0.15% alkoxylatedC6-C16 alcohol 0.15% alkoxylated alkylphenol 0.08% olefin sulfonate0.06% Guerbet alkoxylated carboxylate 0.06% carboxylate 18 0.15%alkoxylated C6-C16 alcohol 0.15% alkoxylated alkylphenol 0.05% olefinsulfonate 0.1% Guerbet alkoxylated carboxylate 0.05% disulfonate 19 0.5%olefin sulfonate 0.5% Guerbet alkoxylated carboxylate 0.55% glycosidesor glucosides 20 0.5% olefin sulfonate 0.5% Guerbet alkoxylatedcarboxylate 0.5% glycosides or glucosides 0.25% alkoxylated C6-C16alcohol 21 0.5% olefin sulfonate 0.5% Guerbet alkoxylated carboxylate0.5% glycosides or glucosides 0.5% alkoxylated C6-C16 alcohol 22 0.5%olefin sulfonate 0.5% Guerbet alkoxylated carboxylate 1% glycosides orglucosides 0.5% alkoxylated C6-C16 alcohol 23 0.05% olefin sulfonate0.05% Guerbet alkoxylated carboxylate 0.05% glycosides or glucosides0.05% alkoxylated C6-C16 alcohol 24 0.075% glycosides or glucosides0.075% alkoxylated C6-C16 alcohol 25 0.1% alkoxylated C6-C16 alcohol0.05% disulfonate 26 0.1% alkoxylated C6-C16 alcohol 0.05% disulfonate0.03% hydroxyalkyl alkylammonium chloride 27 0.03% olefin sulfonate0.04% Guerbet alkoxylated carboxylate 0.08% glycosides or glucosides0.05% alkoxylated C6-C16 alcohol 28 0.4% olefin sulfonate 0.4% Guerbetalkoxylated carboxylate 0.7% glycosides or glucosides 0.5% alkoxylatedC6-C16 alcohol 29 0.05% olefin sulfonate 0.1% glycosides or glucosides0.05% alkoxylated C6-C16 alcohol 30 0.05% olefin sulfonate 0.1% alkylpolyglucoside 0.05% alkoxylated C6-C16 alcohol 31 0.05% olefin sulfonate0.1% glycosides or glucosides 0.05% alkoxylated C6-C16 alcohol 32 0.05%olefin sulfonate 0.1% alkyl polyglucoside 0.05% alkoxylated C6-C16alcohol 33 0.05% olefin sulfonate 0.1% alkyl polyglucoside 0.05%alkoxylated C6-C16 alcohol 34 0.05% olefin sulfonate 0.05% glycosides orglucosides 0.05% alkoxylated C6-C16 alcohol 0.05% carboxylate 35 0.05%olefin sulfonate 0.05% glycosides or glucosides 0.05% alkoxylated C6-C16alcohol 0.05% carboxylate 36 0.05% olefin sulfonate 0.05% alkylpolyglucoside 0.05% alkoxylated C6-C16 alcohol 37 0.06% olefin sulfonate0.05% alkyl polyglucoside 0.04% alkoxylated C6-C16 alcohol 38 0.04%olefin sulfonate 0.08% glycosides or glucosides 0.05% alkoxylated C6-C16alcohol 0.03% disulfonate 39 0.035% olefin sulfonate 0.075% glycosidesor glucosides 0.05% alkoxylated C6-C16 alcohol 0.04% disulfonate 400.035% olefin sulfonate 0.07% glycosides or glucosides 0.045%alkoxylated C6-C16 alcohol 0.05% disulfonate 41 0.1% alkoxylated C6-C16alcohol 0.1% disulfonate 42 0.25% Guerbet alkoxylated carboxylate 0.25%olefin sulfonate 0.5% glycosides or glucosides 0.5% co-solvent 43 0.075%alkoxylated C12-C22 alcohol 0.075% disulfonate 44 0.075% alkoxylatedC6-C16 Guerbet alcohol 0.075% disulfonate 45 0.075% alkoxylated C6-C16Guerbet alcohol 0.075% disulfonate 46 0.075% alkoxylated C6-C16 alcohol0.075% disulfonate 47 0.075% disulfonate 0.075% alkoxylated C6-C16alcohol 48 0.0625% disulfonate 0.0875% alkoxylated C6-C16 alcohol 490.055% disulfonate 0.095% alkoxylated C6-C16 alcohol 50 0.075%disulfonate 0.075% alkoxylated C6-C16 alcohol 51 1% alkoxylated C6-C16alcohol 0.5% disulfonate 52 1% alkoxylated C6-C16 alcohol 53 1%alkoxylated C6-C16 alcohol 2.25% sulfosuccinate 54 0.25% Guerbetalkoxylated carboxylate 1% alkoxylated C6-C16 alcohol 2.25%sulfosuccinate 55 0.25% Guerbet alkoxylated carboxylate 1% alkoxylatedalkylphenol 2.25% sulfosuccinate 56 0.25% Guerbet alkoxylatedcarboxylate 1% alkoxylated C6-C16 alcohol 57 0.25 Guerbet alkoxylatedcarboxylate 1% alkoxylated alkylphenol 58 0.65% carboxylate 0.35%alkoxylated C6-C16 alcohol 59 0.325% carboxylate 0.925% alkoxylatedC6-C16 alcohol 60 0.25% olefin sulfonate 1.0% alkoxylated C6-C16 alcohol61 0.15% olefin sulfonate 0.2% Guerbet alkoxylated carboxylate 0.92%carboxylate 62 0.65% carboxylate 0.35% second carboxylate 63 0.65%carboxylate 0.35% alkoxylated C6-C16 alcohol 1% olefin sulfonate 64 1%alkoxylated alcohol 1% olefin sulfonate 65 0.5% alkoxylated alcohol 0.5%olefin sulfonate 0.25% carboxylate 66 0.6% co-solvent 0.6% olefinsulfonate 67 0.6% co-solvent 0.3% disulfonate 0.3% olefin sulfonate 680.6% Guerbet alkoxylated carboxylate 0.6% disulfonate 69 0.6% co-solvent0.4% disulfonate 0.2% olefin sulfonate 70 0.5% alkoxylated C6-C16alcohol 0.4% disulfonate 0.3% olefin sulfonate 71 1% alkoxylated C6-C16alcohol 72 0.9% alkoxylated C6-C16 alcohol 0.6% disulfonate 73 0.4%alkoxylated C6-C16 alcohol 0.35% disulfonate 0.25% olefin sulfonate 0.5%co-solvent 74 0.25% Guerbet alkoxylated carboxylate 0.5% alkoxylatedC6-C16 alcohol 0.35% disulfonate 0.15% olefin sulfonate 0.35% co-solvent75 0.25% Guerbet alkoxylated carboxylate 0.25% alkoxylated C6-C16alcohol 0.25% olefin sulfonate 0.25% co-solvent 76 0.25% Guerbetalkoxylated carboxylate 0.25% alkoxylated C6-C16 alcohol 0.25% olefinsulfonate 0.25% alkoxylated alcohol 77 0.25% Guerbet alkoxylatedcarboxylate 0.35% olefin sulfonate 0.5% alkoxylated alcohol 78 0.25%Guerbet alkoxylated carboxylate 0.25% alkoxylated C6-C16 alcohol 0.15%olefin sulfonate 0.1% disulfonate 0.25% co-solvent 79 0.25% Guerbetalkoxylated carboxylate 0.25% alkoxylated C6-C16 alcohol 0.25% olefinsulfonate 0.25% glycosides or glucosides 0.25% co-solvent 0.15%disulfonate 80 0.25% Guerbet alkoxylated carboxylate 0.25% olefinsulfonate 0.5% glycosides or glucosides 0.25% co-solvent 81 0.15%alkoxylated C12-C22 alcohol 82 0.075% alkoxylated C12-C22 alcohol 0.075%disulfonate 83 0.075% alkoxylated C12-C22 alcohol 0.075% disulfonate 840.075% alkoxylated C12-C22 alcohol 0.075% alkoxylated C6-C16 Guerbetalcohol 85 0.15% alkoxylated C6-C16 Guerbet alcohol 86 0.075%alkoxylated C6-C16 Guerbet alcohol 0.075% disulfonate 87 0.075%alkoxylated C6-C16 Guerbet alcohol 0.075% disulfonate 0.05% co-solvent88 0.1% alkoxylated C6-C16 alcohol 0.05% disulfonate 89 1% alkoxylatedC6-C16 alcohol 0.5% disulfonate 90 0.075% alkoxylated C6-C16 Guerbetalcohol 0.075% disulfonate 91 0.075% alkoxylated C6-C16 Guerbet alcohol0.125% disulfonate 92 0.075% alkoxylated C12-C22 alcohol 0.125%disulfonate 93 0.075% alkoxylated C12-C22 alcohol 0.075% disulfonate 940.075% alkoxylated C6-C16 Guerbet alcohol 0.075% disulfonate 95 0.1%alkoxylated C6-C16 Guerbet alcohol 0.05% disulfonate 96 0.075%alkoxylated C6-C16 Guerbet alcohol 0.075% disulfonate 97 0.075%alkoxylated C6-C16 alcohol 0.075% disulfonate 98 0.075% alkoxylatedC6-C16 Guerbet alcohol 0.075% disulfonate 99 0.1% alkoxylated C6-C16alcohol 0.05% disulfonate 100 0.09% alkoxylated C6-C16 alcohol 0.06%disulfonate 101 0.1% alkoxylated C6-C16 alcohol 0.1% disulfonate 0.1%Guerbet alkoxylated carboxylate 102 0.1% alkoxylated C6-C16 alcohol 0.1%disulfonate 103 0.65% Guerbet alkoxylated carboxylate 0.35% olefinsulfonate 0.33% alkoxylated alkylphenol 0.5% co-solvent 0.25% secondco-solvent 104 0.075% alkoxylated C6-C16 alcohol 0.075% benzenesulfonicacid, decyl(sulfophenoxy)-disodium salt 105 0.15% alkoxylated C6-C16alcohol 0.05% benzenesulfonic acid, decyl(sulfophenoxy)-disodium salt106 0.05% alkoxylated alkylphenol 0.05% disulfonate 0.05% alkoxylatedC6-C16 alcohol 107 0.05% alkoxylated C6-C16 alcohol mixture 0.1%disulfonate 108 0.1% alkoxylated C6-C16 alcohol mixture 0.1% disulfonate109 0.05% alkoxylated alkylphenol 0.1% disulfonate 0.05% alkoxylatedC6-C16 alcohol 110 0.05% alkoxylated alkylphenol 0.05% disulfonate 0.05%alkoxylated C6-C16 alcohol 111 0.9% Guerbet alkoxylated carboxylate 0.9%alkoxylated C6-C16 alcohol 1.2% olefin sulfonate 0.225% co-solvent 1121% alkoxylated C6-C16 alcohol 1% olefin sulfonate 113 1% alkoxylatedC6-C16 alcohol 0.75% olefin sulfonate 0.5% disulfonate 114 1%alkoxylated C6-C16 alcohol 0.75% olefin sulfonate 0.3% disulfonate 1150.5% alkoxylated C6-C16 alcohol 0.85% olefin sulfonate 0.15% disulfonate116 0.9% Guerbet alkoxylated carboxylate 0.9% alkoxylated C6-C16 alcohol1.2% olefin sulfonate 0.225% co-solvent 117 1% alkoxylated C6-C16alcohol 0.75% olefin sulfonate 0.3% disulfonate 118 0.9% Guerbetalkoxylated carboxylate 0.9% alkoxylated C6-C16 alcohol 1.2% olefinsulfonate 0.225% co-solvent 119 0.5% Guerbet alkoxylated carboxylate0.5% alkoxylated C6-C16 alcohol 0.15% olefin sulfonate 0.35% disulfonate0.5% alkoxylated alkylphenol 0.13% co-solvent 120 0.5% Guerbetalkoxylated carboxylate 0.5% alkoxylated C6-C16 alcohol 0.5% disulfonate0.5% alkoxylated alkylphenol 0.13% co-solvent 121 0.5% Guerbetalkoxylated carboxylate 0.5% alkoxylated C6-C16 alcohol 0.5% olefinsulfonate 0.5% disulfonate 122 0.5% C6-C16 alcohol alkoxylatedcarboxylate 0.25% alkoxylated C6-C16 alcohol 0.15% olefin sulfonate0.35% disulfonate 123 0.5% Guerbet alkoxylated carboxylate 0.25% C6-C16alcohol alkoxylated carboxylate 0.5% alkoxylated C6-C16 alcohol 0.5%olefin sulfonate 0.1% disulfonate 0.5% co-solvent 124 0.5% C6-C16alcohol alkoxylated carboxylate 0.25% alkoxylated C6-C16 alcohol 0.15%olefin sulfonate 0.35% disulfonate 125 0.5% Guerbet alkoxylatedcarboxylate 0.5% alkoxylated C6-C16 alcohol 0.15% olefin sulfonate 0.35%disulfonate 0.25% cetyl betaine 126 0.5% Guerbet alkoxylated carboxylate0.25% C6-C16 alcohol alkoxylated carboxylate 0.5% alkoxylated C6-C16alcohol 0.5% olefin sulfonate 0.1% disulfonate 0.5% co-solvent 0.02%cetyl Betaine 127 0.5% olefin sulfonate 0.5% alkyl aryl sulfonate 0.5%disulfonate 128 0.5% olefin sulfonate 0.5% alkyl aryl sulfonate 0.5%disulfonate 2% co-solvent 129 0.5% olefin sulfonate 0.5% alkyl arylsulfonate 0.5% disulfonate 2% co-solvent 130 0.5% olefin sulfonate 0.5%alkyl aryl sulfonate 0.5% disulfonate 0.5% alkoxylated C6-C16 alcohol0.5% co-solvent 131 0.5% olefin sulfonate 0.5% alkyl aryl sulfonate 0.5%disulfonate 0.5% alkoxylated alkylphenol 132 0.5% olefin sulfonate 0.5%alkyl aryl sulfonate 0.5% alkoxylated alkylphenol

Polymers

In some embodiments, the aqueous compositions can further include apolymer, such as a viscosity enhancing water-soluble polymer. In someembodiments, the water-soluble polymer may be a biopolymer such asxanthan gum or scleroglucan, a synthetic polymer such as polyacryamide,hydrolyzed polyarcrylamide or co-polymers of acrylamide and acrylicacid, 2-acrylamido 2-methyl propane sulfonate or N-vinyl pyrrolidone, asynthetic polymer such as polyethylene oxide, or any other highmolecular weight polymer soluble in water or brine. In some embodiments,the polymer is polyacrylamide (PAM), partially hydrolyzedpolyacrylamides (HPAM), and copolymers of 2-acrylamido-2-methylpropanesulfonic acid or sodium salt or mixtures thereof, and polyacrylamide(PAM) commonly referred to as AMPS copolymer and mixtures of thecopolymers thereof. In one embodiment, the viscosity enhancingwater-soluble polymer is polyacrylamide or a co-polymer ofpolyacrylamide. In one embodiment, the viscosity enhancing water-solublepolymer is a partially (e.g. 20%, 25%, 30%, 35%, 40%, 45%) hydrolyzedanionic polyacrylamide. Molecular weights of the polymers may range fromabout 10,000 Daltons to about 20,000,000 Daltons. In some embodiments,the viscosity enhancing water-soluble polymer is used in the range ofabout 100 to about 5000 ppm concentration, such as from about 1000 to2000 ppm (e.g., in order to match or exceed the reservoir oil viscosityunder the reservoir conditions of temperature and pressure). The polymercan be a powder polymer, a liquid polymer, or an emulsion polymer.

Some examples of polymers are discussed in the following: U.S. Pat. Nos.9,909,053, 9,896,617, 9,902,894, 9,902,895, U.S. Patent ApplicationPublication No. 2017/0158947, U.S. Patent Application Publication No.2017/0158948, and U.S. Patent Application Publication No. 2018/0155505,each of which is incorporated by reference in its entirety. Moreexamples of polymers may be found in Dwarakanath et al., “PermeabilityReduction Due to use of Liquid Polymers and Development of RemediationOptions,” SPE 179657, SPE IOR Symposium in Tulsa, 2016, which isincorporated by reference in its entirety.

Additional Components

In some embodiments, the aqueous compositions can further include aco-solvent. Suitable co-solvents include alcohols, such as lower carbonchain alcohols such as isopropyl alcohol, ethanol, n-propyl alcohol,n-butyl alcohol, sec-butyl alcohol, n-amyl alcohol, sec-amyl alcohol,n-hexyl alcohol, sec-hexyl alcohol and the like; alcohol ethers,polyalkylene alcohol ethers, polyalkylene glycols,poly(oxyalkylene)glycols, poly(oxyalkylene)glycol ethers, ethoxylatedphenol, or any other common organic co-solvent or combinations of anytwo or more co-solvents. In one embodiment, the co-solvent can comprisealkyl ethoxylate (C1-C6)-XEO X=1-30-linear or branched. In someembodiments, the co-solvent can comprise ethylene glycol butyl ether(EGBE), diethylene glycol monobutyl ether (DGBE), triethylene glycolmonobutyl ether (TEGBE), ethylene glycol dibutyl ether (EGDE),polyethylene glycol monomethyl ether (mPEG), or any combination thereof.

The aqueous compositions provided herein may include more than oneco-solvent. Thus, in embodiments, the aqueous composition includes aplurality of different co-solvents. Where the aqueous compositionincludes a plurality of different co-solvents, the different co-solventscan be distinguished by their chemical (structural) properties. Forexample, the aqueous composition may include a first co-solvent, asecond co-solvent and a third co-solvent, wherein the first co-solventis chemically different from the second and the third co-solvent, andthe second co-solvent is chemically different from the third co-solvent.In embodiments, the plurality of different co-solvents includes at leasttwo different alcohols (e.g., a C₁-C₆ alcohol and a C₁-C₄ alcohol). Inembodiments, the aqueous composition includes a C₁-C₆ alcohol and aC₁-C₄ alcohol. In embodiments, the plurality of different co-solventsincludes at least two different alkoxy alcohols (e.g., a C₁-C₆ alkoxyalcohol and a C₁-C₄ alkoxy alcohol). In embodiments, the aqueouscomposition includes a C₁-C₆ alkoxy alcohol and a C₁-C₄ alkoxy alcohol.In embodiments, the plurality of different co-solvents includes at leasttwo co-solvents selected from the group consisting of alcohols, alkylalkoxy alcohols and phenyl alkoxy alcohols. For example, the pluralityof different co-solvents may include an alcohol and an alkyl alkoxyalcohol, an alcohol and a phenyl alkoxy alcohol, or an alcohol, an alkylalkoxy alcohol and a phenyl alkoxy alcohol. The alkyl alkoxy alcohols orphenyl alkoxy alcohols provided herein have a hydrophobic portion (alkylor aryl chain), a hydrophilic portion (e.g., an alcohol) and optionallyan alkoxy (ethoxylate or propoxylate) portion. Thus, in embodiments, theco-solvent is an alcohol, alkoxy alcohol, glycol ether, glycol orglycerol. Suitable co-solvents are known in the art, and include, forexample, co-surfactants described in U.S. Patent Application PublicationNo. 2013/0281327 which is hereby incorporated herein in its entirety.

The co-solvents can have a concentration within the aqueous compositionof at least 0.01% by weight (e.g., at least 0.02% by weight, at least0.03% by weight, at least 0.04% by weight, at least 0.05% by weight, atleast 0.06% by weight, at least 0.07% by weight, at least 0.08% byweight, at least 0.09% by weight, at least 0.1% by weight, at least0.15% by weight, at least 0.2% by weight, at least 0.25% by weight, atleast 0.3% by weight, at least 0.35% by weight, at least 0.4% by weight,at least 0.45% by weight, at least 0.5% by weight, at least 0.55% byweight, at least 0.6% by weight, at least 0.65% by weight, at least 0.7%by weight, at least 0.75% by weight, at least 0.8% by weight, at least0.85% by weight, at least 0.9% by weight, at least 0.95% by weight, atleast 1% by weight, at least 1.25% by weight, at least 1.5% by weight,at least 1.75% by weight, at least 2% by weight, at least 2.5% byweight, at least 3% by weight, at least 3.5% by weight, at least 4% byweight, or at least 4.5% by weight), based on the total weight of theaqueous composition. In some embodiments, the co-solvents can have aconcentration within the aqueous composition of 5% by weight or less(e.g., 4.5% by weight or less, 4% by weight or less, 3.5% by weight orless, 3% by weight or less, 2.5% by weight or less, 2% by weight orless, 1.75% by weight or less, 1.5% by weight or less, 1.25% by weightor less, 1% by weight or less, 0.95% by weight or less, 0.9% by weightor less, 0.85% by weight or less, 0.8% by weight or less, 0.75% byweight or less, 0.7% by weight or less, 0.65% by weight or less, 0.6% byweight or less, 0.55% by weight or less, 0.5% by weight or less, 0.45%by weight or less, 0.4% by weight or less, 0.35% by weight or less, 0.3%by weight or less, 0.25% by weight or less, 0.2% by weight or less,0.15% by weight or less, 0.1% by weight or less, 0.09% by weight orless, 0.08% by weight or less, 0.07% by weight or less, 0.06% by weightor less, 0.05% by weight or less, 0.04% by weight or less, 0.03% byweight or less, or 0.02% by weight or less), based on the total weightof the aqueous composition.

The co-solvents can have a concentration within the aqueous compositionranging from any of the minimum values described above to any of themaximum values described above. For example, in some embodiments, theco-solvents can have a concentration within the aqueous composition offrom 0.01% to 5% by weight (e.g., from 0.01% to 2.5% by weight, from0.05% to 5% by weight, from 0.05% to 2.5% by weight, from 0.05% to 1% byweight, or from 0.05% to 0.5% by weight), based on the total weight ofthe aqueous composition.

Optionally, the aqueous composition can further comprise additionalcomponents for use in oil and gas operations, such as a frictionreducer, a gelling agent, a crosslinker, a breaker, a pH adjustingagent, a non-emulsifier agent, an iron control agent, a corrosioninhibitor, a scale inhibitor, a biocide, a clay stabilizing agent, achelating agent, a proppant, a wettability alteration chemical, or anycombination thereof.

In some embodiments, the aqueous composition can further include a gas.For instance, the gas may be combined with the aqueous composition toreduce its mobility by decreasing the liquid flow in the pores of thesolid material (e.g., rock). In some embodiments, the gas may besupercritical carbon dioxide, nitrogen, natural gas or mixtures of theseand other gases. Some example aqueous compositions are included in thetable below.

Components of Aqueous Composition Example (in weight percent) 1 0.9%Guerbet alkoxylated carboxylate 0.9% alkoxylated C6-C16 alcohol 1.2%olefin sulfonate 0.225% co-solvent 2% sodium tetraborate 1% acetic acid2 1% alkoxylated C6-C16 alcohol 1% olefin sulfonate 2% sodiumtetraborate 1% acetic acid 3 1% alkoxylated C6-C16 alcohol 0.75% olefinsulfonate 0.5% disulfonate 2% sodium tetraborate 1% acetic acid 4 1%alkoxylated C6-C16 alcohol 0.75% olefin sulfonate 0.3% disulfonate 2%sodium tetraborate 1% acetic acid 5 0.5% alkoxylated C6-C16 alcohol0.85% olefin sulfonate 0.15% disulfonate 2% sodium tetraborate 1% aceticacid 6 0.9% Guerbet alkoxylated carboxylate 0.9% alkoxylated C6-C16alcohol 1.2% olefin sulfonate 0.225% co-solvent 2% sodium tetraborate 1%citric acid 7 1% alkoxylated C6-C16 alcohol 0.75% olefin sulfonate 0.3%disulfonate 2% sodium tetraborate 1% citric acid 8 0.9% Guerbetalkoxylated carboxylate 0.9% alkoxylated C6-C16 alcohol 1.2% olefinsulfonate 0.225% co-solvent 2% sodium tetraborate 1.1% citric acid 90.5% Guerbet alkoxylated carboxylate 0.25% C6-C16 alcohol alkoxylatedcarboxylate 0.5% alkoxylated C6-C16 alcohol 0.5% olefin sulfonate 0.1%disulfonate 0.5% co-solvent 2% sodium tetraborate 1% acetic acid 10 0.5%C6-C16 alcohol alkoxylated carboxylate 0.25% alkoxylated C6-C16 alcohol0.15% olefin sulfonate 0.35% disulfonate 2% sodium tetraborate 1% aceticacid 11 0.5% Guerbet alkoxylated carboxylate 0.25% C6-C16 alcoholalkoxylated carboxylate 0.5% alkoxylated C6-C16 alcohol 0.5% olefinsulfonate 0.1% disulfonate 0.5% co-solvent 0.02% cetyl betaine 2% sodiumtetraborate 1% acetic acid

Methods

The aqueous compositions described herein can be used in a variety ofoil and gas operations, including an EOR operation (e.g., an improvedoil recovery (IOR) operation, a polymer (P) flooding operation, asurfactant (S) flooding operation, an alkaline-polymer (AP) floodingoperation, an alkaline-surfactant (AS) flooding operation, asurfactant-polymer (SP) flooding operation, aalkaline-surfactant-polymer (ASP) flooding operation, a conformancecontrol operation, or any combination thereof). Moreover, the aqueouscompositions described herein can be used in a variety of oil and gasoperations, including hydraulic fracturing operations. In oneembodiment, the aqueous compositions can be used as an injection fluid.In another embodiment, the aqueous compositions can be included in aninjection fluid. In another embodiment, the aqueous compositions can beused as a hydraulic fracturing fluid. In another embodiment, the aqueouscompositions can be included in a hydraulic fracturing fluid. In short,in certain embodiments, the aqueous compositions described herein can beused in hydrocarbon recovery.

Methods for improving the recovery of hydrocarbons from a subterraneanformation containing the hydrocarbons therewithin can comprise injectingan aqueous composition comprising (i) a borate-acid buffer, (ii) asurfactant package, a water-soluble polymer, or any combination thereof,and (iii) water into the subterranean formation through a wellbore influid communication with the subterranean formation. The borate-acidbuffer can exhibit a capacity to buffer at a pH of from 6.0 to 8.5(e.g., a pH of from 6.5 to 7.5). In some cases, the borate-acid buffercan exhibit a capacity to buffer at a pH below the point of zero chargeof the formation.

The subterranean formation can be a subsea reservoir and/or thesubsurface reservoir. In some embodiments, the subterranean formationcan have a permeability of from 26 millidarcy to 40,000 millidarcy.

In some embodiments, there is no need to drill the wellbore. In someembodiments, the wellbore has been drilled and completed, andhydrocarbon production has occurred from the wellbore. In otherembodiments, methods can optionally include one or more of drilling thewellbore, completing the wellbore, and producing hydrocarbons from thewellbore (prior to injection of the aqueous composition).

In some embodiments, the subterranean formation can have a temperatureof at least 75° F. (e.g., at least 80° F., at least 85° F., at least 90°F., at least 95° F., at least 100° F., at least 105° F., at least 110°F., at least 115° F., at least 120° F., at least 125° F., at least 130°F., at least 135° F., at least 140° F., at least 145° F., at least 150°F., at least 155° F., at least 160° F., at least 165° F., at least 170°F., at least 175° F., at least 180° F., at least 190° F., at least 200°F., at least 205° F., at least 210° F., at least 215° F., at least 220°F., at least 225° F., at least 230° F., at least 235° F., at least 240°F., at least 245° F., at least 250° F., at least 255° F., at least 260°F., at least 265° F., at least 270° F., at least 275° F., at least 280°F., at least 285° F., at least 290° F., at least 295° F., at least 300°F., at least 305° F., at least 310° F., at least 315° F., at least 320°F., at least 325° F., at least 330° F., at least 335° F., at least 340°F., or at least 345° F.). In some embodiments, the subterraneanformation can have a temperature of 350° F. or less (e.g., 345° F. orless, 340° F. or less, 335° F. or less, 330° F. or less, 325° F. orless, 320° F. or less, 315° F. or less, 310° F. or less, 305° F. orless, 300° F. or less, 295° F. or less, 290° F. or less, 285° F. orless, 280° F. or less, 275° F. or less, 270° F. or less, 265° F. orless, 260° F. or less, 255° F. or less, 250° F. or less, 245° F. orless, 240° F. or less, 235° F. or less, 230° F. or less, 225° F. orless, 220° F. or less, 215° F. or less, 210° F. or less, 205° F. orless, 200° F. or less, 195° F. or less, 190° F. or less, 185° F. orless, 180° F. or less, 175° F. or less, 170° F. or less, 165° F. orless, 160° F. or less, 155° F. or less, 150° F. or less, 145° F. orless, 140° F. or less, 135° F. or less, 130° F. or less, 125° F. orless, 120° F. or less, 115° F. or less, 110° F. or less, 105° F. orless, 100° F. or less, 95° F. or less, 90° F. or less, 85° F. or less,or 80° F. or less).

The subterranean formation can have a temperature ranging from any ofthe minimum values described above to any of the maximum valuesdescribed above. For example, in some embodiments, the subterraneanformation can have a temperature of from 75° F. to 350° F.(approximately 24° C. to 176° C.), from 150° F. to 250° F.(approximately 66° C. to 121° C.), from 110° F. to 350° F.(approximately 43° C. to 176° C.), from 110° F. to 150° F.(approximately 43° C. to 66° C.), from 150° F. to 200° F. (approximately66° C. to 93° C.), from 200° F. to 250° F. (approximately 93° C. to 121°C.), from 250° F. to 300° F. (approximately 121° C. to 149° C.), from300° F. to 350° F. (approximately 149° C. to 176° C.), from 110° F. to240° F. (approximately 43° C. to 116° C.), or from 240° F. to 350° F.(approximately 116° C. to 176° C.).

In some embodiments, the salinity of the subterranean formation can beat least 5,000 ppm TDS (e.g., at least 25,000 ppm TDS, at least 50,000ppm TDS, at least 75,000 ppm TDS, at least 100,000 ppm TDS, at least125,000 ppm TDS, at least 150,000 ppm TDS, at least 175,000 ppm TDS, atleast 200,000 ppm TDS, at least 225,000 ppm TDS, at least 250,000 ppmTDS, or at least 275,000 ppm TDS). In some embodiments, the salinity ofthe subterranean formation can be 300,000 ppm TDS or less (e.g., 275,000ppm TDS or less, 250,000 ppm TDS or less, 225,000 ppm TDS or less,200,000 ppm TDS or less, 175,000 ppm TDS or less, 150,000 ppm TDS orless, 125,000 ppm TDS or less, 100,000 ppm TDS or less, 75,000 ppm TDSor less, 50,000 ppm TDS or less, or 25,000 ppm TDS or less).

The salinity of subterranean formation can range from any of the minimumvalues described above to any of the maximum values described above. Forexample, in some embodiments, the salinity of the subterranean formationcan be from 5,000 ppm TDS to 300,000 ppm TDS (e.g., from 100,000 ppm to300,000 ppm TDS).

In some embodiments, the subterranean formation can be oil-wet. In someembodiments, the subterranean formation can be water-wet. In someembodiments, the subterranean formation can be mixed-wet (heterogeneouswet). In some embodiments, the subterranean formation can beintermediate-wet.

The wellbore in the second step can be an injection wellbore, and themethod can further comprise providing a production wellbore in fluidcommunication with the subterranean formation and spaced-apart from theinjection wellbore. In these embodiments, injection of the aqueouscomposition can increase the flow of hydrocarbons to the productionwellbore.

In some embodiments, methods of hydrocarbon recovery can further includea recycling step. For example, in some embodiments, methods ofhydrocarbon recovery can further comprise producing production fluidfrom the production well, the production fluid including at least aportion of the aqueous composition; and separating the portion of theaqueous composition from the production fluid. The portion of theaqueous composition can be injected into at least one wellbore (e.g., aninjection well, the same wellbore discussed in the second step or adifferent wellbore, etc.).

The wellbore in the second step can also be a wellbore for hydraulicfracturing that is in fluid communication with the subsurfacesubterranean.

In some embodiments, the borate-acid buffer can be combined with othercomponents (e.g., a surfactant package, a polymer, etc.) and water in acontinuous process to form the aqueous composition (which issubsequently injected). In other examples, the borate-acid buffer andone or more additional components (e.g., a surfactant package, apolymer, etc.) can be present in a single concentrated package with canbe diluted with water in a continuous process to form the aqueouscomposition (which is subsequently injected).

In certain embodiments, the aqueous compositions described herein can beused treatment operations in an unconventional formation.

In some embodiments, the aqueous composition can be used in a completionand/or fracturing operation. For example, the aqueous composition can beinjected into an unconventional subterranean formation to form and/orextend fractures within the formation. In certain embodiments, thefracturing operation can comprise combining a surfactant package and aborate-acid buffer described herein with an aqueous-based injectionfluid to form an aqueous composition; and injecting the aqueouscomposition through a wellbore and into the unconventional subterraneanformation at a sufficient pressure and at a sufficient rate to fracturethe unconventional subterranean formation. In some embodiments, thewellbore is a hydraulic fracturing wellbore associated with a hydraulicfracturing well, for example, that may have a substantially verticalportion only, or a substantially vertical portion and a substantiallyhorizontal portion below the substantially vertical portion. In someembodiments, the fracturing operation can be performed in a new well(e.g., a well that has not been previously fractured). In otherembodiments, the aqueous composition can be used in a fracturingoperation in an existing well (e.g., in a refracturing operation). Insome examples, the borate-acid buffer can exhibit a capacity to bufferat a pH of from 6.0 to 8.5 (e.g., a pH of from 6.5 to 7.5). In someexamples, the borate-acid buffer can exhibit a capacity to buffer at apH below the point of zero charge of the formation.

In some embodiments, the method can comprise performing a fracturingoperation on a region of the unconventional subterranean formationproximate to a new wellbore. In some embodiments, the method cancomprise performing a fracturing operation on a region of theunconventional subterranean formation proximate to an existing wellbore.In some embodiments, the method can comprise performing a refracturingoperation on a previously fractured region of the unconventionalsubterranean formation proximate to a new wellbore. In some embodiments,the method can comprise performing a refracturing operation on apreviously fractured region of the unconventional subterranean formationproximate to an existing wellbore. In some embodiments, the method cancomprise performing a fracturing operation on a naturally fracturedregion of the unconventional subterranean formation proximate to a newwellbore (e.g., an infill well). In some embodiments, the method cancomprise performing a fracturing operation on a naturally fracturedregion of the unconventional subterranean formation proximate to anexisting wellbore.

In cases where the fracturing method comprises a refracturing methods,the previously fractured region of the unconventional reservoir can havebeen fractured by any suitable type of fracturing operation. Forexample, the fracturing operation may include hydraulic fracturing,fracturing using electrodes such as described in U.S. Pat. Nos.9,890,627, 9,840,898, U.S. Patent Publication No. 2018/0202273, orfracturing with any other available equipment or methodology. In someembodiments, the fracturing operation can further comprise adding atracer to the aqueous composition prior to introducing or along with theaqueous composition or through the wellbore into the subterraneanformation; recovering the tracer from the fluids produced from theunconventional subterranean formation through the wellbore, fluidsrecovered from a different wellbore in fluid communication with theunconventional subterranean formation, or any combination thereof; andcomparing the quantity of tracer recovered from the fluids produced tothe quantity of tracer introduced. For example, in the context of a newwell, a tracer can be added along with (as part of) the aqueouscomposition. In the context of an existing well, a tracer can be addedprior to introduction of the aqueous composition, along with (as partof) the aqueous composition, or any combination thereof. The tracer cancomprise a proppant tracer, an oil tracer, a water tracer, or anycombination thereof. Example tracers are known in the art, anddescribed, for example, in U.S. Pat. No. 9,914,872 and Ashish Kumar etal., Diagnosing Fracture-Wellbore Connectivity Using Chemical TracerFlowback Data, URTeC 2902023, Jul. 23-25, 2018, page 1-10, Texas, USA.

The aqueous compositions described herein can be used at varying pointsthroughout a fracturing operation. For example, the aqueous compositionscan be used as an injection fluid during the first, middle or last partof the fracturing process, or throughout the entire fracturing process.In some embodiments, the fracturing process can include a plurality ofstages and/or sub-stages. For example, the fracturing process caninvolve sequential injection of fluids in different stages, with each ofthe stages employing a different aqueous-based injection fluid system(e.g., with varying properties such as viscosity, chemical composition,etc.). Example fracturing processes of this type are described, forexample, in U.S. Patent Application Publication Nos. 2009/0044945 and2015/0083420, each of which is hereby incorporated herein by referencein its entirely. In these embodiments, the aqueous composition can beused as an injection fluid (optionally with additional components)during any or all of the stages and/or sub-stages.

In some embodiments, the aqueous composition can be used as part of areservoir stimulation operation. In some embodiments, the stimulationoperations can be performed on an unconventional subterranean formation.For example, in some embodiments, the stimulation operation can beperformed on an unconventional subterranean formation (e.g., anunconventional subterranean formation having a permeability of from1.0×10⁻⁶ millidarcy to 25.9 millidarcy). In other embodiments, thestimulation can be performed on a conventional subterranean formation(e.g., a subterranean formation having a permeability of from 26millidarcy to 40,000 millidarcy). In some stimulation examples, theborate-acid buffer can exhibit a capacity to buffer at a pH of from 6.0to 8.5 (e.g., a pH of from 6.5 to 7.5). In some examples, theborate-acid buffer can exhibit a capacity to buffer at a pH below thepoint of zero charge of the formation.

In some stimulation operations, the aqueous composition can be injectedto alter the wettability of existing fractures within the formation(without further fracturing the formation significantly by eitherforming new fractures within the formation and/or extending the existingfractures within the formation). In such stimulation operations, noproppant is used, and fluid injection generally occurs at a lowerpressure.

In some cases, the existing fractures can be naturally occurringfractures present within a formation. For example, in some embodiments,the formation can comprise naturally fractured carbonate or naturallyfractured sandstone. The presence or absence of naturally occurringfractures within a subterranean formation can be assessed using standardmethods known in the art, including seismic surveys, geology, outcrops,cores, logging, reservoir characterization including preparing grids,etc.

In some embodiments, methods for stimulating an unconventionalsubterranean formation with a fluid can comprise introducing an aqueouscomposition described herein through a wellbore into the unconventionalsubterranean formation; allowing the aqueous composition to imbibe intoa rock matrix of the unconventional subterranean formation for a periodof time; and producing fluids from the unconventional subterraneanformation through the wellbore.

In these methods, the same wellbore can be used for both introducing theaqueous composition and producing fluids from the unconventionalsubterranean formation. In some embodiments, introduction of the aqueouscomposition can increase the production of hydrocarbons from the samewellbore, from a different wellbore in fluid communication with theunconventional subterranean formation, or any combination thereof.

In some embodiments, the stimulation operation can further comprisepreparing the aqueous composition. For example, in some embodiments, thestimulation operation can further comprise combining a borate-acidbuffer and a surfactant package described herein with water to form theaqueous composition. In some embodiments when used in a stimulationoperation, the aqueous composition can have a total surfactantconcentration of from 0.2% to 5% by weight, based on the total weight ofthe low particle size injection fluid.

In some embodiments, introducing the aqueous composition describedherein through a wellbore into the unconventional subterranean formationcan comprise injecting the aqueous composition through the wellbore andinto the unconventional subterranean formation at a sufficient pressureand at a sufficient rate to stimulate hydrocarbon production fromnaturally occurring fractures in the unconventional subterraneanformation.

The aqueous composition can be allowed to imbibe into the rock matrix ofthe unconventional subterranean formation for varying periods of timedepending on the nature of the rock matrix. The imbibing can occurduring the introducing step, between the introducing and producing step,or any combination thereof. In some examples, the aqueous compositioncan be allowed to imbibe into the rock matrix of the unconventionalsubterranean formation for at least one day (e.g., at least two days, atleast three days, at least four days, at least five days, at least sixdays, at least one week, at least two weeks, at least three weeks, atleast one month, at least two months, at least three months, at leastfour months, or at least five months). In some examples, the aqueouscomposition can be allowed to imbibe into the rock matrix of theunconventional subterranean formation for six months or less (e.g., fivemonths or less, four months or less, three months or less, two months orless, one month or less, three weeks or less, two weeks or less, oneweek or less, six days or less, five days or less, four days or less,three days or less, or two days or less).

The aqueous composition can be allowed to imbibe into the rock matrix ofthe unconventional subterranean formation for a period of time rangingfrom any of the minimum values described above to any of the maximumvalues described above. For example, the aqueous composition can beallowed to imbibe into the rock matrix of the unconventionalsubterranean formation for from one day to six months. In one example,the wellbore can be a new wellbore; and the aqueous composition can beallowed to imbibe into the rock matrix of the unconventionalsubterranean formation for from two weeks to one month. In anotherexample, the wellbore can be a wellbore proximate to a previouslyfractured region of the unconventional subterranean formation; and theaqueous composition can be allowed to imbibe into the rock matrix of theunconventional subterranean formation for from one day to two weeks.

In some embodiments, the wellbore used in the stimulation operation mayhave a substantially vertical portion only, or a substantially verticalportion and a substantially horizontal portion below the substantiallyvertical portion.

In some embodiments, the stimulation methods described herein cancomprise stimulating a naturally fractured region of the unconventionalsubterranean formation proximate to a new wellbore (e.g., an infillwell). In some embodiments, the stimulation methods described herein cancomprise stimulating a naturally fractured region of the unconventionalsubterranean formation proximate to an existing wellbore.

In some embodiments, the stimulation methods described herein cancomprise stimulating a previously fractured or previously refracturedregion of the unconventional subterranean formation proximate to a newwellbore (e.g., an infill well). In some embodiments, the stimulationmethods described herein can comprise stimulating a previously fracturedor previously refractured region of the unconventional subterraneanformation proximate to an existing wellbore.

The previous fracturing operation may include hydraulic fracturing,fracturing using electrodes such as described in U.S. Pat. Nos.9,890,627, 9,840,898, U.S. Patent Publication No. 2018/0202273, orfracturing with any other available equipment or methodology. Theprevious refracturing operation may include hydraulic fracturing,fracturing using electrodes such as described in U.S. Pat. Nos.9,890,627, 9,840,898, U.S. Patent Publication No. 2018/0202273, orrefracturing with any other available equipment or methodology. In someembodiments, after a formation that has fractures, such as naturallyoccurring factures, fractures from a fracture operation, fractures froma refracturing operation, or any combination thereof, the fracturedformation may be stimulated. For example, a formation may be stimulatedafter a sufficient amount of time has passed since the fracturingoperation with electrodes or refracturing operation with electrodesoccurred in that formation so that the electrical pulses utilized tofracture or refracture that formation do not substantially affect theaqueous composition.

In some embodiments, the stimulation operation can further compriseadding a tracer to the aqueous composition prior to introducing or alongwith the aqueous composition or through the wellbore into thesubterranean formation; recovering the tracer from the fluids producedfrom the unconventional subterranean formation through the wellbore,fluids recovered from a different wellbore in fluid communication withthe unconventional subterranean formation, or any combination thereof;and comparing the quantity of tracer recovered from the fluids producedto the quantity of tracer introduced.

In another aspect, a method of displacing a hydrocarbon material incontact with a solid material is provided. The method includescontacting a hydrocarbon material with an aqueous composition asdescribed herein, wherein the hydrocarbon material is in contact with asolid material. The hydrocarbon material is allowed to separate from thesolid material thereby displacing the hydrocarbon material in contactwith the solid material. In some examples, the borate-acid buffer canexhibit a capacity to buffer at a pH of from 6.0 to 8.5 (e.g., a pH offrom 6.5 to 7.5). In some examples, the borate-acid buffer can exhibit acapacity to buffer at a pH below the point of zero charge of the solidmaterial.

In other embodiments, the hydrocarbon material is unrefined petroleum(e.g., in a petroleum reservoir). In some further embodiments, theunrefined petroleum is a light oil. A “light oil” as provided herein isan unrefined petroleum with an API gravity greater than 30. In someembodiments, the API gravity of the unrefined petroleum is greater than30. In other embodiments, the API gravity of the unrefined petroleum isgreater than 40. In some embodiments, the API gravity of the unrefinedpetroleum is greater than 50. In other embodiments, the API gravity ofthe unrefined petroleum is greater than 60. In some embodiments, the APIgravity of the unrefined petroleum is greater than 70. In otherembodiments, the API gravity of the unrefined petroleum is greater than80. In some embodiments, the API gravity of the unrefined petroleum isgreater than 90. In other embodiments, the API gravity of the unrefinedpetroleum is greater than 100. In some other embodiments, the APIgravity of the unrefined petroleum is between 30 and 100.

In other embodiments, the hydrocarbons or unrefined petroleum cancomprise crude having an H₂S concentration of at least 0.5%, a CO₂concentration of 0.3%, or any combination thereof.

In some embodiments, the hydrocarbons or unrefined petroleum cancomprise crude having an H₂S concentration of at least 0.5% (e.g., atleast 1%, at least 1.5%, at least 2%, at least 2.5%, at least 3%, atleast 3.5%, at least 4%, or at least 4.5%). In some embodiments, thehydrocarbons or unrefined petroleum can comprise crude having an H₂Sconcentration of 5% or less (4.5% or less, 4% or less, 3.5% or less, 3%or less, 2.5% or less, 2% or less, 1.5% or less, or 1% or less).

The hydrocarbons or unrefined petroleum can comprise crude having an H₂Sconcentration ranging from any of the minimum values described above.For example, in some embodiments, the hydrocarbons or unrefinedpetroleum can comprise crude having an H₂S concentration of from 0.5% to5% (e.g., from 0.5% to 2.5%).

In some embodiments, the hydrocarbons or unrefined petroleum cancomprise crude having a CO₂ concentration of at least 0.3% (e.g., atleast 0.5%, at least 1%, at least 1.5%, at least 2%, at least 2.5%, atleast 3%, at least 3.5%, at least 4%, or at least 4.5%). In someembodiments, the hydrocarbons or unrefined petroleum can comprise crudehaving a CO₂ concentration of 5% or less (4.5% or less, 4% or less, 3.5%or less, 3% or less, 2.5% or less, 2% or less, 1.5% or less, 1% or less,or 0.5% or less).

The hydrocarbons or unrefined petroleum can comprise crude having a CO₂concentration ranging from any of the minimum values described above.For example, in some embodiments, the hydrocarbons or unrefinedpetroleum can comprise crude having a CO₂ concentration of from 0.3% to5% (e.g., from 0.3% to 2.5%).

The solid material may be a natural solid material (i.e., a solid foundin nature such as rock). The natural solid material may be found in apetroleum reservoir. In some embodiments, the method is an enhanced oilrecovery method. Enhanced oil recovery methods are well known in theart. A general treatise on enhanced oil recovery methods is BasicConcepts in Enhanced Oil Recovery Processes edited by M. Baviere(published for SCI by Elsevier Applied Science, London and New York,1991). For example, in an enhanced oil recovery method, the displacingof the unrefined petroleum in contact with the solid material isaccomplished by contacting the unrefined with a compound providedherein, wherein the unrefined petroleum is in contact with the solidmaterial. The unrefined petroleum may be in an oil reservoir. Thecompound or composition provided herein can be pumped into the reservoirin accordance with known enhanced oil recovery parameters. The compoundcan be pumped into the reservoir as part of the aqueous compositionsprovided herein and, upon contacting the unrefined petroleum, form anemulsion composition provided herein.

In some embodiments, the natural solid material can be rock or regolith.The natural solid material can be a geological formation such asclastics or carbonates. The natural solid material can be eitherconsolidated or unconsolidated material or mixtures thereof. Thehydrocarbon material may be trapped or confined by “bedrock” above orbelow the natural solid material. The hydrocarbon material may be foundin fractured bedrock or porous natural solid material. In otherembodiments, the regolith is soil. In other embodiments, the solidmaterial can be, for example, oil sand or tar sands.

In other embodiments, the solid material can comprise equipmentassociated with an oil and gas operation. For example, the solidmaterial can comprise surface processing equipment, downhole equipment,pipelines and associated equipment, pumps, and other equipment whichcontacts hydrocarbons during the course of an oil and gas operation.

By way of non-limiting illustration, examples of certain embodiments ofthe present disclosure are given below.

EXAMPLES

The examples are set forth below to illustrate the methods and resultsaccording to the disclosed subject matter. These examples are notintended to be inclusive of all aspects of the subject matter disclosedherein, but rather to illustrate representative methods and results.These examples are not intended to exclude equivalents and variations ofthe present invention which are apparent to one skilled in the art.

Efforts have been made to ensure accuracy with respect to numbers (e.g.,amounts, temperature, etc.) but some errors and deviations should beaccounted for. Unless indicated otherwise, parts are parts by weight,percents associated with components of compositions are percents byweight, based on the total weight of the composition including thecomponents, temperature is in ° C. or is at ambient temperature, andpressure is at or near atmospheric.

Example 1 Contact Angle and Phase Behavior with Sodium Tetraborate inHigh Hardness Brine

There are known complications associated with the use of high hardnessaqueous fluids in oil and gas operations. Borate-acid buffers provide ameans to address many of the complications associated with the use ofhigh hardness fluids.

Divalent Cation Sequestration. Divalent cations in injection andformation water inhibit surfactant performance. Typical sulfonatedsurfactants such as IOS and AOS precipitate out in the presence ofhardness and cannot be used. One trick frequently used is to addethoxylated sulfates or sulfonates to the olefin sulfonates to allowmixed surfactant formulations to tolerate divalent cations. However,this approach is expensive. Another alternative is to soften injectionbrine by removing the divalent cations. The third approach is to use achelating agent such as EDTA. EDTA is a common chelating agent that hasbeen used in laboratory studies. However, it is too expensive to use inthe field applications. Borax is used in the detergent industry tochelate calcium but have not been applied in the petroleum industry dueto the fact high pH of borate derivatives (>8.5) causes precipitationwith Ca and Mg.

Surfactant Stability Improvement. Surfactants, especially alcohol ethercarboxylates and alcohol ether sulfates can degrade at low pH conditions(<=6.5) typically observed during long-term storage. Hence the alcoholether sulfate and carboxylates typically come with a shelf life. Typicalalcohol ether carboxylates and sulfates are buffered with alkali to highpH during manufacturing (>10) to provide a longer shelf life. However,if the injection brines contain high divalent ion concentrations (Ca andMg), there is potential for precipitation.

Wettability Alteration. Wettability alteration of oil-wet reservoirs towater-wet can speed up the rate of oil recovery and increase ultimateoil recovery from oil-wet reservoirs. In fractured carbonate and shalereservoirs, which are typically oil-wet, change in wettability cangreatly improve oil recovery. Generally, two methods of wettabilityalteration exist. Surfactants can be injected to change wettability or adifferent salinity brine with altered divalent/monovalent ion ratios canbe injected to change wettability (Brine Chemistry Optimization).Traditional alkali, such as sodium carbonate has also been known tochange wettability of oil-wet rocks to water-wet but such alkali cannotbe used in presence of Ca and Mg due to precipitations caused by highpH.

Neutron log Signal Improvement. Often, logging equipment are used inwells to determine saturation of fluids near wellbore. A commonly usedlogging equipment is a neutron log. However, in low porosity reservoirs,the signal difference between crude oil and water is near the noise ofthe equipment and cannot be accurately distinguished. It is necessary insuch situations to incorporate a neutron absorbing material into theinjected fluid to improve signal difference between crude oil and water.Boron is a neutron absorbing material. Most soluble borons come inborate forms and should not be used in hard brine due to Mg and Caprecipitations caused by high pH.

Methods

Formulation A was prepared in in a high hardness brine (50,000 ppm TDS,with approximately 12,000 ppm Mg²⁺ and Ca²⁺), brine containing 0.5%sodium tetraborate and 0.275% citric acid, and brine containing 2%sodium tetraborate and 1% acetic acid. The pH of the surfactant stockwas adjusted to approximately pH 7.5.

TABLE 1 Components of Example Formulations. Formulation A 0.65% Guerbetalkoxylated carboxylate 0.35% olefin sulfonate 0.33% alkoxylatedalkylphenol 0.5% co-solvent 0.25% second co-solvent Formulation B 0.9%Guerbet alkoxylated carboxylate 1.2% olefin sulfonate 0.9% alkoxylatedC12-C22 alcohol

The phase behavior of all three formulations was evaluated. All of thesalinities were recorded based on brine salinity only. The sodiumtetraborate and acids were not included for purposes of the salinitycalculation. In this example, values for the optimum salinity andaqueous stability remained largely unchanged (±5%) upon addition of theborate-acid buffer. In all cases, the aqueous stability was greater thanthe optimum salinity.

Formulation B was prepared in in a high hardness brine (50,000 ppm TDS,with approximately 12,000 ppm Mg²⁺ and Ca²⁺) and high hardness brine(50,000 ppm TDS, with approximately 12,000 ppm Mg²⁺ and Ca²⁺) containing2% sodium tetraborate and 1% acetic acid. The pH was adjusted toapproximately pH 7 at room temperature.

The phase behavior of both formulations was evaluated. The values forthe optimum salinity and aqueous stability remained largely unchanged(±5%) upon addition of the borate-acid buffer. In all cases, the aqueousstability was greater than the optimum salinity.

Carbonate substrates were aged in crude oil at reservoir temperature for1 month. The aged substrates were the immersed in a solution(brine/surfactant solution) at 230° F. for varying duration of time (1hr, 1 day, 5 days). The oil contact angles were then measure with theaqueous solution aged substrate at room temperature with crude oil andhigh hardness brine (50,000 ppm). Contact angles were measured at 3different points of the substrate and averaged. The results are shown inFIGS. 1-2 and Table 2.

TABLE 2 Contact Angle Measurements. Oil Contact Angle FollowingDifferent Immersion Periods Composition Tested 1 hr 4 hrs 8 hrs 1 day 2days 7 days High Hardness Brine 160° 130° 155° 160° 160° 155° HighHardness Brine + 160°  90°  90°  80°  50° <30° 2% Sodium Tetraborate +1% Acetic Acid + Formulation B

Results and Discussion

By incorporating a borate-acid buffer in a surfactant solution, neutronlog signal can be improvement when measuring fluid saturation changes insingle well pilots before and after surfactant injection. In theseembodiments, a sodium tetraborate solution was buffered to pH<8 withacid to prevent precipitation of hardness ions (e.g., Ca and Mg ions) ininjection and formation brines. For example, borate-acid buffer caninclude sodium tetraborate and acetic acid at pH=˜7, and sodiumtetraborate and citric acid at a similar pH range. In these instances, amass ratio of 2 parts sodium tetraborate and 1-1.2 part acetic acid orcitric acid were used. However, other borate compounds and/or acids maybe used to prepare the borate-acid buffer.

The acid can be any acid (organic and inorganic). In some cases, theacid can be an organic acid. In certain cases, the organic acid can forma conjugate base upon deprotonation that can chelate divalent metalions. Some examples of possible acids include acetic acid, citric acid,boric acid, tartaric acid, hydrochloric acid, succinic acid, as well ascombinations thereof. The borate can be any water-soluble borate. Someexamples of borates include sodium tetraborate, sodium tetraboratedecahydrate, calcium tetraborate, sodium borate, sodium metaborate, aswell as combinations thereof. Alternatively, borate-acid buffers can beformed by combining boric acid with a suitable alkali (e.g., sodium andpotassium salts of the acids above).

The borate-acid buffer was found to chelate/sequestere divalent cations(e.g., Ca²⁺ and Mg²⁺) in the brine. This can improve surfactantstability and performance in the solution. In surfactant floodsperformed using borate-acid buffers and a blend of surfactants, improvedpropagation of the surfactant blend (with a decrease or nochromatographic separation) was observed. In addition, the borate-acidbuffer improved surfactant stability and reduced absorption, retention,or any combination thereof during the course of the surfactant floodingoperation. Further, in high hardness fluids (e.g., seawater), IOSsurfactants precipitate in the presence of high hardness ions. Byincorporating the borate-acid buffer, the hardness ions can bestabilized (e.g., through chelation of the hardness ions by the boratecompound, the conjugate base/acid, or any combination thereof). Thisallows a wider range of surfactants, including surfactants such as IOS,that would typically precipitate in the presence of hardness ions, to beincorporated in the aqueous composition. Borate-acid buffers aresignificantly cheaper than commonly used chelants such as EDTA.Sequestering divalent cations can allow the use of lower costsurfactants that are typically incompatible with hard brines (e.g., foruse in EOR operations). Likewise, the borate-acid buffer can similarlyallow for other agents that are incompatible with hard brine (e.g.,polymers, friction reducers, etc.) to be included in compositionscomprising hard water or hard brine.

In addition to effective chelation, contact angle measurements showedthat wettability alteration of oil-wet rock plugs to water-wet stateoccurred faster and to a greater degree in the presence of a borate-acidbuffer and surfactant package. This suggests synergistic behaviorbetween the borate-acid buffer and surfactants used to alterwettability. The borate-acid buffer (alone or in combination with one ormore surfactants) can increase the wettability (water-wettability) of aformation. By including the borate-acid buffer, the kinetics ofwater-wettability can be enhanced (i.e., the water-wettability can beincreased more quickly than with an identical formulation lacking theborate-acid buffer). In addition, the magnitude of the water-wettabilitycan be enhanced (i.e., the formation can be made more water-wet than aformation treated with an identical formulation lacking the borate-acidbuffer).

Further, the borate-acid buffer can buffer the acidity of hydrocarbonsin a reservoir. By way of example, the sour crude reservoirs can containCO₂ and H₂S, which can degrade certain surfactants that are unstable atlow pH. In addition, certain anionic surfactants (e.g., carboxylates)can become protonated under reservoir conditions with high CO₂, H₂S, orany combination thereof, effectively altering surfactant performance inrecovery operations performed in these reservoirs. By including theborate-acid buffer, these impacts can be minimized, allowing for a widerrange of surfactants to be used in these applications.

Finally, by including the borate-acid buffer, components in theformulation (e.g., surfactants) which are pH sensitive can be protectedfrom degradation. For example, the borate-acid buffer can improve thestability of alcohol ether carboxylate and sulfate surfactants (e.g.,alcohol ether sulfate surfactants) from degradation due to long-termstorage before use.

In view of these findings, the borate-acid buffers described herein canbe incorporated into injection fluids used to improve oil recovery frompetroleum reservoirs. The injection fluids may be brine, surfactantsolution, polymer solution, surfactant polymer solution, foam, etc. Ifthe injection fluids contain surfactants, the borate-acid buffer can beincluded into a concentrated surfactant blend (package) used to preparethe injection fluid. The applications can be conventional chemical EOR,brine chemistry optimization, and improved oil recovery by imbibition inlow permeability and unconventional reservoirs. Borate-acid buffers canalso be used to improve fracturing fluid performance by, for example,improving friction reducer and surfactant performance.

Example 2 Borates Improve the Performance of Example SurfactantSolutions

The performance of example surfactant formulations (with and without theaddition of a borate-acid buffer) were evaluated. Specifically, phasebehavior and coreflood studies were performed using two surfactantformulations with and without the addition of a borate-acid buffer.

The components of Formulations C-Formulation F are show in the tablebelow. All formulations were prepared using a hard synthetic brineincluding Nat, Ca²⁺, Mg²⁺, and and having a TDS of approximately 36,800ppm. A 2:1 (by weight) mixture of sodium tetraborate and acetic acid wasadded as the example borate-acid buffer in Formulation D and FormulationE. The formulations were evaluated using example crude oils havingviscosities of 2.1 cP at 95° C.

TABLE 2 Components of Example Formulations. Formulation C 1% Guerbetalkoxylated carboxylate 1% olefin sulfonates 1% alkoxylated C12-C22alcohol Formulation D 1% Guerbet alkoxylated carboxylate 1% olefinsulfonates 1% alkoxylated C12-C22 alcohol 1% sodium tetraborate bufferFormulation E 1% Guerbet alkoxylated carboxylate 1% olefin sulfonates0.75% alkoxylated C12-C22 alcohol Formulation F 1% Guerbet alkoxylatedcarboxylate 1% olefin sulfonates 0.75% alkoxylated C12-C22 alcohol 0.5%sodium tetraborate buffer

FIG. 3 is a plot illustrating the phase behavior of Formulation C(without borate-acid buffer) with an example crude oil at 95° C. Forcomparison, FIG. 4 is a plot illustrating the phase behavior ofFormulation D (including 1% by weight borate-acid buffer) with anexample crude oil at 95° C. FIG. 5 is a plot illustrating the phasebehavior of Formulation F (including 0.5% by weight borate-acid buffer)with an example crude oil at 95° C. Addition of the borate-acid bufferdid not significantly impact the aqueous stability (optimum salinity) ofthe surfactant formulations.

Coreflood experiments were conducted using sandstone cores (see FIGS.7-9 ). Without a borate buffer, at one pore volume residual oil recoverywas 72% (with 55% oil cut). Further, no surfactant production wasobserved. Upon addition of a borate-acid buffer, at one pore volumeresidual oil recovery increased to 91% (with 60-75% oil cut). Further,surfactant production was observed. This suggests reduced surfactantabsorption/retention when a borate-acid buffer is included in thesurfactant formulation. This result suggests that reduced quantities ofsurfactants can be used when incorporating a borate-acid buffer. Thiseffect was observed to be particularly beneficial in the case offormulations that include a surfactant bearing a carboxylate moiety(e.g., a branched or unbranched C6-C32:PO(0-65):EO(0-100)-carboxylate).Spontaneous imbibition tests with oil-wet carbonate core were conductedwith a high pressure/high temperature imbibition cell. The core wassaturated with 65-70% crude oil and placed inside the imbibition cell.The core was surrounded by fracture which is filled with an examplesurfactant solution (SF), optionally including 2% by weight of aborate-acid buffer (a 2:1 (by weight) mixture of sodium tetraborate andacetic acid). The test temperature was 230° F. and the test pressure wasapproximately 1000 psi. The oil production versus time was measured. Thescope of this test was to evaluate how the addition of the borate-acidbuffer to the SF solution enhanced oil recovery by (1) shiftingwettability from oil-wet to water-wet and (2) reducing IFT between oiland water. The oil production was driven by capillary pressure inducedby wettability alteration from oil-wet to water-wet and reduced IFT.

FIG. 9 illustrates the effect of the borate-acid buffer on imbibitionrecovery. As shown in FIG. 9 , the addition of the borate-acid buffer tothe SF solution resulting in increased imbibition recovery, whichconfirms that the rock became more water-wet. FIG. 10 shows that theaddition of the borate-acid buffer to the SF solution shifted theoptimum IFT from 0.1 mN/m to 0.03 mN/m and the optimum imbibitionrecovery from 50 to 55%.

The compounds, compositions, and methods of the appended claims are notlimited in scope by the specific compounds, compositions, and methodsdescribed herein, which are intended as illustrations of a few aspectsof the claims. Any compounds, compositions, and methods that arefunctionally equivalent are intended to fall within the scope of theclaims. Various modifications of the compounds, compositions, andmethods in addition to those shown and described herein are intended tofall within the scope of the appended claims. Further, while onlycertain representative compounds, compositions, and method stepsdisclosed herein are specifically described, other combinations of thecompounds, compositions, and method steps also are intended to fallwithin the scope of the appended claims, even if not specificallyrecited. Thus, a combination of steps, elements, components, orconstituents may be explicitly mentioned herein or less, however, othercombinations of steps, elements, components, and constituents areincluded, even though not explicitly stated.

The term “comprising” and variations thereof as used herein is usedsynonymously with the term “including” and variations thereof and areopen, non-limiting terms. Although the terms “comprising” and“including” have been used herein to describe various embodiments, theterms “consisting essentially of” and “consisting of” can be used inplace of “comprising” and “including” to provide for more specificembodiments of the invention and are also disclosed. Other than wherenoted, all numbers expressing geometries, dimensions, and so forth usedin the specification and claims are to be understood at the very least,and not as an attempt to limit the application of the doctrine ofequivalents to the scope of the claims, to be construed in light of thenumber of significant digits and ordinary rounding approaches.

Unless defined otherwise, all technical and scientific terms used hereinhave the same meanings as commonly understood by one of skill in the artto which the disclosed invention belongs. Publications cited herein andthe materials for which they are cited are specifically incorporated byreference.

What is claimed is:
 1. A method for stimulating a subterraneanformation, the method comprising: introducing an aqueous compositioncomprising (i) a borate-acid buffer, (ii) a surfactant package; (iii)water; and (iv) optionally a water-soluble polymer into the subterraneanformation through a wellbore in fluid communication with thesubterranean formation; and allowing the aqueous composition to imbibeinto a rock matrix of the subterranean formation for a period of time;wherein the borate-acid buffer exhibits a capacity to buffer at a pH offrom 6.0 to 8.5; wherein the borate-acid buffer is present in aneffective amount to chelate divalent metal ions present in the water orin water present in the subterranean formation.
 2. The method of claim1, wherein the method further comprises producing fluids from thesubterranean formation through the wellbore.
 3. The method of claim 2,wherein the producing fluids comprise hydrocarbons.
 4. The method ofclaim 3, wherein the hydrocarbons further comprise CO₂, H₂S, or anycombination thereof.
 5. The method of claim 1, wherein the subterraneanformation comprises an unconventional subterranean formation.
 6. Themethod of claim 5, wherein the method comprises stimulating a naturallyfractured region of the unconventional subterranean formation proximateto a new wellbore, stimulating a naturally fractured region of theunconventional subterranean formation proximate to an existing wellbore,stimulating a previously fractured or previously refractured region ofthe unconventional subterranean formation proximate to a new wellbore,stimulating a previously fractured or previously refractured region ofthe unconventional subterranean formation proximate to an existingwellbore or any combination thereof.
 7. The method of claim 1, whereinthe method further comprises ceasing introduction of the aqueouscomposition through the wellbore into the subterranean formation beforesaid allowing step.
 8. The method of claim 1, wherein the period of timeis from one day to six months.
 9. The method of claim 1, furthercomprising: adding a tracer to the aqueous composition prior tointroducing or along with the aqueous composition or through thewellbore into the subterranean formation; recovering the tracer from thefluids produced from the subterranean formation through the wellbore,from fluids produced from a different well in fluidic communication withthe subterranean formation, or any combination thereof; and comparingthe quantity of tracer recovered from the fluids produced to thequantity of tracer introduced.
 10. The method of claim 1, wherein theborate-acid buffer is present in the aqueous composition in an amount offrom 0.01% to 2% by weight, based on the total weight of the aqueouscomposition.
 11. The method of claim 1, wherein the borate-acid bufferexhibits a capacity to buffer at a pH below a point of zero charge ofthe subterranean formation.
 12. The method of claim 1, wherein theborate-acid buffer comprises a borate compound and a conjugate base ofan acid, wherein the borate compound and the conjugate base of theorganic acid are present at a weight ratio of from 1:1 to 5:1.
 13. Themethod of claim 1, wherein the aqueous composition comprises asurfactant package, and wherein the surfactant package comprises aprimary surfactant and optionally one or more secondary surfactants. 14.The method of claim 13, wherein the primary surfactant comprises ananionic surfactant selected from a sulfonate, a disulfonate, a sulfate,a disulfate, a sulfosuccinate, a disulfosuccinate, a carboxylate, adicarboxylate, or any combination thereof.
 15. The method of claim 14,wherein the anionic surfactant comprises one of the following: abranched or unbranched C6-C32:PO(0-65):EO(0-100)-carboxylate; a C10-C30internal olefin sulfonate; a C8-C30 alkyl benzene sulfonate (ABS); asulfosuccinate surfactant; a surfactant defined by the formula belowR¹—R²—R³ wherein R¹ comprises a branched or unbranched, saturated orunsaturated, cyclic or non-cyclic, hydrophobic carbon chain having 6-32carbon atoms and an oxygen atom linking R¹ and R²; R² comprises analkoxylated chain comprising at least one oxide group selected from thegroup consisting of ethylene oxide, propylene oxide, butylene oxide, andcombinations thereof; and R³ comprises a branched or unbranchedhydrocarbon chain comprising 2-12 carbon atoms and from 2 to 5carboxylate groups; or a surfactant defined by the formula below

wherein R⁴ is, individually for each occurrence, a branched orunbranched, saturated or unsaturated, cyclic or non-cyclic, hydrophobiccarbon chain having 6-32 carbon atoms; and M represents a counterion.16. The method of claim 13, wherein the primary surfactant has aconcentration within the composition of from 0.05% to 5% by weight,based on the total weight of the aqueous composition.
 17. The method ofclaim 1, wherein when present the water-soluble polymer comprises asynthetic polymer.
 18. The method of claim 1, wherein when present thewater-soluble polymer comprises polyacrylamide or a copolymer thereof.19. The method of claim 1, wherein the surfactant package comprises aprimary surfactant comprising a branched or unbranchedC6-C32:PO(0-65):EO(0-100)-carboxylate, a dicarboxylate, or anycombination thereof.
 20. The method of claim 1, wherein the subterraneanformation comprises a conventional subterranean formation.
 21. Themethod of claim 1, wherein the period of time is from two weeks to onemonth.